**UNITED STATESSECURITIES AND EXCHANGE COMISSION**

**Washington,D.C. 20549**

**FORM 10-Q**

**x**                              QUARTERLYREPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934

**Forthe quarterly period ended June 30, 2006**

**OR**

**o**                                 TRANSITIONREPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934

**Forthe transition period from                  to                  **

**Commissionfile number 1-10934**

**ENBRIDGE ENERGY PARTNERS, L.P.**

(Exact name of registrantas specified in its charter)

| **Delaware**                                                                                                | ** ** | **39-1715850**       |
|-------------------------------------------------------------------------------------------------------------|------------|----------------------|
| (State or other  jurisdiction of                                                                            |       | (I.R.S. Employer     |
| incorporation or  organization)                                                                             |       | Identification  No.) |
| **1100 Louisiana  Suite 3300  Houston, TX 77002**(Address of principal executive offices and zip code) |
| **(713) 821-2000**(Registrant’s telephone number, including area code)                                 |

 

Indicate by check markwhether the registrant: (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding 12months (or for such shorter period that the registrant was required to filesuch reports), and (2) has been subject to such filing requirements forthe past 90 days. Yes  x  No o

Indicate by check markwhether the registrant is a large accelerated filer, accelerated filer, or a non-acceleratedfiler (as defined in Rule  12b-2 of the Exchange Act). LargeAccelerated Filer xAccelerated Filer o Non-AcceleratedFiler o

Indicate by check markwhether the registrant is a shell company (as defined in Rule 12b-2of the Exchange Act). Yes o  No x

The Registrant had49,938,834 Class A common units outstanding as of July 31, 2006.

 

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**TABLEOF CONTENTS**

|                | ** ** | **PART I. FINANCIAL INFORMATION**                                                                                  | ** ** | ** ** |
|----------------|------------|-------------------------------------------------------------------------------------------------------------------------|------------|------------|
| Item 1.        |       | Financial  Statements                                                                                                   |       | 3          |
|           |       | Consolidated  Statements of Income for the three and six month periods ended June 30,  2006 and 2005               |       | 3          |
|           |       | Consolidated  Statements of Comprehensive Income for the three and six month periods ended  June 30, 2006 and 2005 |       | 4          |
|           |       | Consolidated  Statements of Cash Flows for the six month periods ended June 30, 2006  and 2005                     |       | 5          |
|           |       | Consolidated  Statements of Financial Position as of June 30, 2006 and  December 31, 2005                     |       | 6          |
|           |       | Notes  to Consolidated Financial Statements                                                                             |       | 7          |
| Item  2.       |       | Management’s  Discussion and Analysis of Financial Condition and Results of Operations                             |       | 16         |
| Item  3.       |       | Quantitative  and Qualitative Disclosures About Market Risk                                                             |       | 34         |
| Item 4.        |       | Controls  and Procedures                                                                                                |       | 39         |
| ** **     |       | **PART II.  OTHER INFORMATION**                                                                                    |       |       |
| Item 1.        |       | Legal  Proceedings                                                                                                      |       | 40         |
| Item 1A.       |       | Risk Factors                                                                                                            |       | 40         |
| Item 6.        |       | Exhibits                                                                                                                |       | 42         |
| **Signatures** |       | 43                                                                                                                      |
| **Exhibits**   |       |                                                                                                                    |

 

*In this report, unless the context requires otherwise,references to “we”, “us”, “our”, or the “Partnership” are intended to meanEnbridge Energy Partners, L.P. and its consolidated subsidiaries. ThisQuarterly Report on Form 10-Q contains forward-lookingstatements. These forward-looking statements are identified as anystatement that does not relate strictly to historical or current facts. Theyuse words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,”“intend,” “may,” “plan,” “position,” “projection,” “strategy,” “could,” “would,”or “will” or the negative of those terms or other variations of them or bycomparable terminology. In particular, statements, expressed or implied,concerning future actions, conditions or events or future operating results orthe ability to generate sales, income or cash flow or to make distributions areforward-looking statements. Forward-looking statements are notguarantees of performance. They involve risks, uncertainties and assumptions.Future actions, conditions or events and future results of operations maydiffer materially from those expressed in these forward-lookingstatements. Many of the factors that will determine these results are beyondour ability to control or predict. For additional discussion of risks,uncertainties and assumptions, see “Risk Factors” included in Part I,Item 1A of our Annual Report on Form 10-K for the fiscal year endedDecember 31, 2005 and in Part II, Item 1A of our quarterlyreports on Form 10-Q.*

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**PART I—FINANCIALINFORMATION**

**Item 1.**                        Financial Statements

**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF INCOME**

|                                                                     | ** ** | **Three months ended June 30,**                                 | ** ** | **Six months ended June 30,**                                | ** ** |
|---------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------|------------|
| ** **                                                          | ** ** | **      2006      **    | ** ** | **      2005      ** | ** ** | **      2006      ** | ** ** | **      2005      ** | ** ** |
| ** **                                                          | ** ** | **(unaudited; in millions, except per unit amounts)** | ** ** |
| Operating revenue                                                   |       |                                                                                | $          | 1,424.7                                                                          |       |   |   | $ | 1,332.7 |   |   |   | $ | 3,313.3 |   |   |   | $ | 2,582.8 |   |   |
| Operating expenses                                                  |       |                                                                                |       |                                                                             |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Cost of natural gas (Notes 5  and 10)                               |       |                                                                                | 1,185.6    |                                                                             |       |   | 1,150.4 |   |   |   | 2,833.3 |   |   |   | 2,222.6 |   |   |
| Operating and administrative                                        |       |                                                                                | 87.3       |                                                                             |       |   | 80.4 |   |   |   | 161.2 |   |   |   | 154.8 |   |   |
| Power                                                               |       |                                                                                | 24.2       |                                                                             |       |   | 17.2 |   |   |   | 50.5 |   |   |   | 34.2 |   |   |
| Depreciation and amortization (Note 6)                              |       |                                                                                | 34.0       |                                                                             |       |   | 34.1 |   |   |   | 66.7 |   |   |   | 67.4 |   |   |
|                                                                     |       |                                                                                | 1,331.1    |                                                                             |       |   | 1,282.1 |   |   |   | 3,111.7 |   |   |   | 2,479.0 |   |   |
| Operating income                                                    |       |                                                                                | 93.6       |                                                                             |       |   | 50.6 |   |   |   | 201.6 |   |   |   | 103.8 |   |   |
| Interest expense                                                    |       |                                                                                | (27.6      | )                                                                                |       |   | (25.6 | ) |   |   | (55.5 | ) |   |   | (51.2 | ) |   |
| Other income                                                        |       |                                                                                | 4.4        |                                                                             |       |   | 0.7 |   |   |   | 5.4 |   |   |   | 1.3 |   |   |
| Net income                                                          |       |                                                                                | $          | 70.4                                                                             |       |   |   | $ | 25.7 |   |   |   | $ | 151.5 |   |   |   | $ | 53.9 |   |   |
| Net income allocable to common and i-units                          |       |                                                                                | $          | 63.2                                                                             |       |   |   | $ | 19.9 |   |   |   | $ | 137.1 |   |   |   | $ | 42.1 |   |   |
| Net income per common and i-unit  (basic and diluted) (Note 2) |       |                                                                                | $          | 0.96                                                                             |       |   |   | $ | 0.32 |   |   |   | $ | 2.08 |   |   |   | $ | 0.69 |   |   |
| Weighted average units  outstanding                                 |       |                                                                                | 65.9       |                                                                             |       |   | 61.9 |   |   |   | 65.8 |   |   |   | 61.3 |   |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

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**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME**

| ** **                                   | ** ** | **Three months ended**                         | ** ** | **Six months ended**                           | ** ** |
|----------------------------------------------|------------|----------------------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                                   | ** ** | **June 30,**                                        | ** ** | **June 30,**                                        | ** ** |
| ** **                                   | ** ** | **    2006    ** | ** ** | **    2005    ** | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                   | ** ** | **(unaudited; in millions)**                   | ** ** |
| Net income                                   |       |                                                     | $          | 70.4                                                     |       |   |   | $ | 25.7 |   |   | $ | 151.5 |   | $ | 53.9 |   |
| Other  comprehensive income (loss) (Note 10) |       |                                                     | (30.3      | )                                                        |       |   | (11.5 | ) |   | 3.8 |   | (85.7 | ) |
| Comprehensive income  (loss)                 |       |                                                     | $          | 40.1                                                     |       |   |   | $ | 14.2 |   |   | $ | 155.3 |   | $ | (31.8 | ) |

 

The accompanying notes are an integral part of these consolidated financial statements.

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**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF CASH FLOWS**

|                                                                                    | ** ** | **Six months ended June 30,**                                            | ** ** |
|------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------------------|------------|
| ** **                                                                         | ** ** | **       2006       ** | ** ** | **       2005       ** | ** ** |
| ** **                                                                         | ** ** | **(unaudited; in millions)**                                                       | ** ** |
| Cash provided by operating activities                                              |       |                                                                                         |       |   |   |   |   |   |   |
| Net income                                                                         |       |                                                                                         | $          | 151.5 |   |   |   | $ | 53.9 |   |   |
| Adjustments to reconcile net  income to net cash provided by operating activities: |       |                                                                                         |       |   |   |   |   |   |   |
| Depreciation and  amortization (Note 6)                                            |       |                                                                                         | 66.7       |   |   |   | 67.4 |   |   |
| Derivative fair value (gain)  loss (Note 10)                                       |       |                                                                                         | (29.4      | ) |   |   | 16.8 |   |   |
| Inventory market  price adjustment (Note 5)                                        |       |                                                                                         | 9.7        |   |   |   | — |   |   |
| Other                                                                              |       |                                                                                         | 1.0        |   |   |   | (0.3 | ) |   |
| Changes in operating assets and liabilities, net of  cash acquired:                |       |                                                                                         |       |   |   |   |   |   |   |
| Receivables, trade and other                                                       |       |                                                                                         | (33.1      | ) |   |   | (5.8 | ) |   |
| Due from General  Partner and affiliates                                           |       |                                                                                         | 14.2       |   |   |   | (13.8 | ) |   |
| Accrued receivables                                                                |       |                                                                                         | 239.6      |   |   |   | (2.2 | ) |   |
| Inventory (Note  5)                                                                |       |                                                                                         | (26.5      | ) |   |   | (10.2 | ) |   |
| Current and long-term  other assets                                                |       |                                                                                         | (4.3       | ) |   |   | (2.8 | ) |   |
| Due to General  Partner and affiliates                                             |       |                                                                                         | 11.0       |   |   |   | 20.7 |   |   |
| Accounts payable and other  (Note 4)                                               |       |                                                                                         | (6.6       | ) |   |   | (17.3 | ) |   |
| Accrued purchases                                                                  |       |                                                                                         | (221.7     | ) |   |   | 16.9 |   |   |
| Interest payable                                                                   |       |                                                                                         | —     |   |   |   | 4.1 |   |   |
| Property and  other taxes payable                                                  |       |                                                                                         | (5.1       | ) |   |   | (3.7 | ) |   |
| Net cash provided by  operating activities                                         |       |                                                                                         | 167.0      |   |   |   | 123.7 |   |   |
| Cash used in investing activities                                                  |       |                                                                                         |       |   |   |   |   |   |   |
| Additions to property, plant  and equipment                                        |       |                                                                                         | (285.2     | ) |   |   | (174.7 | ) |   |
| Changes in  construction payables                                                  |       |                                                                                         | 4.8        |   |   |   | 2.2 |   |   |
| Asset acquisitions, net of  cash acquired (Note 3)                                 |       |                                                                                         | (33.2      | ) |   |   | (185.9 | ) |   |
| Other                                                                              |       |                                                                                         | 0.1        |   |   |   | 0.8 |   |   |
| Net cash used in investing  activities                                             |       |                                                                                         | (313.5     | ) |   |   | (357.6 | ) |   |
| Cash provided by financing activities                                              |       |                                                                                         |       |   |   |   |   |   |   |
| Proceeds from unit  issuances, net                                                 |       |                                                                                         | —     |   |   |   | 127.5 |   |   |
| Distributions to  partners (Note 8)                                                |       |                                                                                         | (113.2     | ) |   |   | (104.0 | ) |   |
| Borrowings (repayments) of  Credit Facility, net (Note 7)                          |       |                                                                                         | 10.0       |   |   |   | (175.0 | ) |   |
| Net issuances of  commercial paper (Note 7)                                        |       |                                                                                         | 269.1      |   |   |   | 390.0 |   |   |
| Repayment on affiliate loan                                                        |       |                                                                                         | (20.0      | ) |   |   | — |   |   |
| Other                                                                              |       |                                                                                         | —     |   |   |   | (0.5 | ) |   |
| Net cash provided by  financing activities                                         |       |                                                                                         | 145.9      |   |   |   | 238.0 |   |   |
| Net increase  (decrease) in cash and cash equivalents                              |       |                                                                                         | (0.6       | ) |   |   | 4.1 |   |   |
| Cash and cash equivalents at  beginning of year                                    |       |                                                                                         | 89.8       |   |   |   | 78.3 |   |   |
| Cash and cash  equivalents at end of period                                        |       |                                                                                         | $          | 89.2 |   |   |   | $ | 82.4 |   |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

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**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF FINANCIAL POSITION**

|                                                                                                | ** ** | **June 30,  2006**                | ** ** | **December 31,  2005** | ** ** |
|------------------------------------------------------------------------------------------------|------------|----------------------------------------|------------|-----------------------------|------------|
| ** **                                                                                     | ** ** | **(unaudited; in millions)** | ** ** |
| **ASSETS**                                                                                     |       |                                   |       |                        |       |   |   |
| Current assets                                                                                 |       |                                   |       |                        |       |   |   |
| Cash and cash equivalents  (Note 4)                                                            |       | $                                      | 89.2       |                        |       | $ | 89.8 |   |   |
| Receivables, trade and other, net of allowance for  doubtful accounts of $4.5 in 2006 and 2005 |       | 142.8                                  |       |                        | 109.7      |   |   |
| Due from General Partner and  affiliates                                                       |       | 5.9                                    |       |                        | 20.1       |   |   |
| Accrued receivables                                                                            |       | 375.7                                  |       |                        | 615.3      |   |   |
| Inventory (Note 5)                                                                             |       | 154.3                                  |       |                        | 138.9      |   |   |
| Other current assets                                                                           |       | 13.7                                   |       |                        | 11.5       |   |   |
|                                                                                                |       | 781.6                                  |       |                        | 985.3      |   |   |
| Property, plant and equipment, net (Notes 3 and 6)                                             |       | 3,314.5                                |       |                        | 3,080.0    |   |   |
| Other assets, net                                                                              |       | 32.8                                   |       |                        | 22.2       |   |   |
| Goodwill (Note 3)                                                                              |       | 265.5                                  |       |                        | 258.2      |   |   |
| Intangibles, net (Note 3)                                                                      |       | 93.5                                   |       |                        | 82.7       |   |   |
|                                                                                           |       | $                                      | 4,487.9    |                        |       | $ | 4,428.4 |   |   |
| **LIABILITIES AND PARTNERS’ CAPITAL**                                                     |       |                                   |       |                        |       |   |   |
| Current liabilities                                                                            |       |                                   |       |                        |       |   |   |
| Due to General Partner and  affiliates                                                         |       | $                                      | 23.5       |                        |       | $ | 12.5 |   |   |
| Accounts payable and other (Note 4)                                                            |       | 240.2                                  |       |                        | 247.9      |   |   |
| Accrued purchases                                                                              |       | 425.0                                  |       |                        | 646.7      |   |   |
| Interest payable                                                                               |       | 11.4                                   |       |                        | 11.4       |   |   |
| Property and other taxes  payable                                                              |       | 16.1                                   |       |                        | 21.8       |   |   |
| Current maturities of long-term debt                                                           |       | 31.0                                   |       |                        | 31.0       |   |   |
|                                                                                                |       | 747.2                                  |       |                        | 971.3      |   |   |
| Long-term debt (Note 7)                                                                        |       | 1,962.0                                |       |                        | 1,682.9    |   |   |
| Loans from General Partner  and affiliates                                                     |       | 131.8                                  |       |                        | 151.8      |   |   |
| Environmental liabilities (Note 9)                                                             |       | 4.9                                    |       |                        | 4.8        |   |   |
| Other long-term liabilities  (Note 10)                                                         |       | 236.1                                  |       |                        | 253.8      |   |   |
|                                                                                           |       | 3,082.0                                |       |                        | 3,064.6    |   |   |
| Commitments and  contingencies (Note 9)                                                        |       |                                   |       |                        |       |   |   |
| Partners’ capital  (Note 8)                                                               |       |                                   |       |                        |       |   |   |
| Class A common units  (Units issued—49,938,834 in 2006 and 2005)                     |       | 1,153.9                                |       |                        | 1,142.4    |   |   |
| Class B common units (Units issued—3,912,750 in  2006 and 2005)                      |       | 68.4                                   |       |                        | 67.2       |   |   |
| i-units (Units  issued—12,187,145 in 2006 and 11,704,948 in 2005)                         |       | 446.4                                  |       |                        | 421.7      |   |   |
| General Partner                                                                                |       | 35.5                                   |       |                        | 34.6       |   |   |
| Accumulated other  comprehensive loss (Note 10)                                                |       | (298.3                                 | )          |                        | (302.1     | ) |   |
|                                                                                           |       | 1,405.9                                |       |                        | 1,363.8    |   |   |
|                                                                                                |       | $                                      | 4,487.9    |                        |       | $ | 4,428.4 |   |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

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**NOTES TO THECONSOLIDATED FINANCIAL STATEMENTS (unaudited)**

**1.**   BASISOF PRESENTATION

The accompanying unauditedinterim consolidated financial statements have been prepared in accordance withaccounting principles generally accepted in the United States of America forinterim consolidated financial information and with the instructions to Form 10-Qand Rule 10-01 of Regulation S-X. Accordingly, they donot include all the information and footnotes required by accounting principlesgenerally accepted in the United States of America for complete consolidatedfinancial statements. In the opinion of management, they contain alladjustments, consisting only of normal recurring adjustments, which managementconsiders necessary to present fairly the financial position as of June 30,2006 and December 31, 2005; the results of operations for the three andsix month periods ended June 30, 2006 and 2005; and cash flows for the sixmonth periods ended June 30, 2006 and 2005. The results of operations forthe three and six month periods ended June 30, 2006, should not be takenas indicative of the results to be expected for the full year due toseasonality of portions of the natural gas business, maintenance activities andthe impact of forward natural gas prices on certain derivative financialinstruments that are accounted for using mark-to-market accounting.In addition, prior period information presented in these consolidated financialstatements includes reclassifications that were made to conform to the currentperiod presentation. These reclassifications have no effect on previouslyreported net income or partners’ capital. The interim consolidated financialstatements should be read in conjunction with our consolidated financialstatements and notes presented in our Annual Report on Form 10-K forthe fiscal year ended December 31, 2005.

**2.**   NETINCOME PER COMMON AND i-UNIT

Netincome per common and i-unit is computed by dividing net income, afterdeduction of Enbridge Energy Company, Inc.’s (the “General Partner”) allocation,by the weighted average number of our Class A and Class B commonunits and i-units outstanding. The General Partner’s allocation is equalto an amount based upon its general partner interest, adjusted to reflect anamount equal to its incentive distributions and an amount required to reflectdepreciation on the General Partner’s historical cost basis for assetscontributed on formation of the Partnership. We have no dilutive securities.Net income per common and i-unit was determined as follows:

|                                                       | ** ** | **Three months ended  June 30,**          | ** ** | **Six months ended  June 30,**            | ** ** |
|-------------------------------------------------------|------------|----------------------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                                            | ** ** | **    2006    ** | ** ** | **    2005    ** | ** ** | **    2006    ** | ** ** | **    2005    ** | ** ** |
| ** **                                            | ** ** | **(in millions, except per unit amounts)**               | ** ** |
| Net income                                            |       |                                                     | $          | 70.4                                                     |       |   |   | $ | 25.7 |   |   |   | $ | 151.5 |   |   |   | $ | 53.9 |   |   |
| Allocations to the  General Partner:                  |       |                                                     |       |                                                     |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Net income allocated to  General Partner              |       |                                                     | (1.4       | )                                                        |       |   | (0.5 | ) |   |   | (3.0 | ) |   |   | (1.1 | ) |   |
| Incentive distributions to General Partner            |       |                                                     | (5.7       | )                                                        |       |   | (5.3 | ) |   |   | (11.3 | ) |   |   | (10.6 | ) |   |
| Historical cost depreciation  adjustments             |       |                                                     | (0.1       | )                                                        |       |   | — |   |   |   | (0.1 | ) |   |   | (0.1 | ) |   |
|                                                  |       |                                                     | (7.2       | )                                                        |       |   | (5.8 | ) |   |   | (14.4 | ) |   |   | (11.8 | ) |   |
| Net income allocable to  common and i-units           |       |                                                     | $          | 63.2                                                     |       |   |   | $ | 19.9 |   |   |   | $ | 137.1 |   |   |   | $ | 42.1 |   |   |
| Weighted average units outstanding                    |       |                                                     | 65.9       |                                                     |       |   | 61.9 |   |   |   | 65.8 |   |   |   | 61.3 |   |   |
| Net income per common and i-unit  (basic and diluted) |       |                                                     | $          | 0.96                                                     |       |   |   | $ | 0.32 |   |   |   | $ | 2.08 |   |   |   | $ | 0.69 |   |   |

 

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**3.**   ACQUISITIONS

In April 2006,we acquired, for $33.2 million in cash, an 80-mile natural gas pipelinethat is complementary to our existing East Texas system. This pipeline providesapproximately 100 MMcf/d of additional transportation capacity and interconnectswith approximately 65 central delivery points.

Thepurchase price and the allocation to assets acquired and liabilities assumedare as follows:

|                                                                    | ** ** | **(dollars in millions)** | ** ** |
|--------------------------------------------------------------------|------------|-------------------------------------|------------|
| Purchase Price:                                                    |       |                                |       |   |   |
| Cash paid, including transaction costs                             |       |                                | $          | 33.2 |   |   |
| Allocation of purchase  price:                                     |       |                                |       |   |   |
| Property, plant and equipment, including  construction in progress |       |                                | 13.0       |   |   |
| Intangibles                                                        |       |                                | 12.8       |   |   |
| Goodwill                                                           |       |                                | 7.4        |   |   |
| Total                                                              |       |                                | $          | 33.2 |   |   |

 

**4.**   CASHAND CASH EQUIVALENTS

We extinguish liabilitieswhen a creditor has relieved us of our obligation, which occurs when ourfinancial institution honors a check that the creditor has presented forpayment. Accordingly, obligations for which we have issued check payments thathave not yet been presented to the financial institution of approximately$38.2 million at June 30, 2006 and $46.5 million at December 31,2005, are included in Accounts payable and other on the Consolidated Statementsof Financial Position.

**5.**   INVENTORY

Inventoryis comprised of the following:

|                                                | ** ** | **June 30,  2006**             | ** ** | **December 31,  2005** | ** ** |
|------------------------------------------------|------------|-------------------------------------|------------|-----------------------------|------------|
| ** **                                     | ** ** | **(dollars in millions)** | ** ** |
| Material and supplies                          |       |                                | $          | 6.1                         |       |   |   | $ | 8.3 |   |   |
| Liquids inventory                              |       |                                | 17.9       |                        |       |   | 11.1 |   |   |
| Natural gas and natural gas  liquids inventory |       |                                | 130.3      |                        |       |   | 119.5 |   |   |
|                                           |       |                                | $          | 154.3                       |       |   |   | $ | 138.9 |   |   |

 

We recorded a $9.7 millionreduction to the cost basis of our natural gas inventory to reflect the marketvalue at June 30, 2006. The lower of cost or market adjustment is includedin the Cost of natural gas in our Marketing segment on our ConsolidatedStatement of Income.

**6.**   PROPERTY,PLANT AND EQUIPMENT

Based on a third-partystudy commissioned by management, revised depreciation rates for the Lakeheadsystem were implemented effective January 1, 2006. The annual compositerate, which represents the expected remaining service life of the pipelinesystem assets, was reduced from 3.20% to 2.63%. Depreciation expense wasapproximately $3.0 million and $5.5 million lower for the three months and sixmonths ended June 30, 2006, respectively, as a result of the newdepreciation rates.

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**7.**   DEBT

***Credit Facility***

In March 2006, we obtained an increase from $800million to $1 billion in the aggregate commitment available to us under theterms of our Credit Facility. At June 30, 2006, we had borrowed $10million under the terms of our Credit Facility, whereas no amounts wereoutstanding at December 31, 2005. We had letters of credit totaling$104.8 million at June 30, 2006, and $149.3 million at December 31,2005. The amounts we may borrow under the terms of our Credit Facility arereduced by the principal amount of our commercial paper issuances and thebalance of our letters of credit outstanding. At June 30, 2006, we couldborrow an additional $285.2 million under the terms of our Credit Facility.

During the six monthsended June 30, 2005, we net settled borrowings of approximately $565million on a non-cash basis.

***Commercial Paper Program***

We can issue up to $600million of commercial paper under the terms of our commercial paper program.However, the amount of commercial paper we may issue is reduced by any balanceof outstanding letters of credit in excess of $400 million. At June 30,2006, we had outstanding $598.4 million of commercial paper, net of unamortizeddiscount of $1.6 million, bearing interest at a weighted average rate of 5.24%.At December 31, 2005, we had $329.3 million of commercial paperoutstanding, net of $0.7 million of unamortized discount, at a weightedaverage interest rate of 4.36%.

**8.**   PARTNERS’CAPITAL

Thefollowing table sets forth our distributions, as approved by the Board ofDirectors of Enbridge Energy Management, L.L.C. (“Enbridge Management”), duringthe six months ended June 30, 2006:

|                  | ** ** | ** **        | ** ** | ** **            | ** ** | ** **       | ** ** | ** **             | ** ** | **Amount of**  | ** ** | ** **     | ** ** | ** **       | ** ** |
|------------------|------------|-------------------|------------|-----------------------|------------|------------------|------------|------------------------|------------|---------------------|------------|----------------|------------|------------------|------------|
| ** **       | ** ** | ** **        | ** ** | ** **            | ** ** | ** **       | ** ** | ** **             | ** ** | **Distribution**    | ** ** | **Retained**   | ** ** | ** **       | ** ** |
| **Distribution** | ** ** | ** **        | ** ** | ** **            | ** ** | ** **       | ** ** | **Cash**               | ** ** | **of i-units** | ** ** | **from**       | ** ** | ** **       | ** ** |
| **Declaration**  | ** ** | **Distribution**  | ** ** | **Record**            | ** ** | **Distribution** | ** ** | **available for** | ** ** | **to i-unit**  | ** ** | **General**    | ** ** | **Distribution** | ** ** |
| **Date**         | ** ** | ** **        | ** ** | **Payment Date** | ** ** | **Date**         | ** ** | **per Unit**      | ** ** | **distribution**    | ** ** | **Holders**(1) | ** ** | **Partner**(2)   | ** ** | **of Cash** | ** ** |
| January 30, 2006 |       | February 14, 2006 |       | February 7, 2006      |       |             | $          | 0.925                  |       |                |       | $              | 67.6       |             |       |   | $ | 10.8 |   |   |   | $ | 0.2 |   |   |   | $ | 56.6 |   |   |
| April 27, 2006   |       | May 15, 2006      |       | May 5, 2006           |       |             | $          | 0.925                  |       |                |       | $              | 67.8       |             |       |   | $ | 11.0 |   |   |   | $ | 0.2 |   |   |   | $ | 56.6 |   |   |
|                  |            |                   |            |                       |            |                  |            |                        |            |                     |            |                |            |                  |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

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(1)      ThePartnership has issued 482,197 i-units to Enbridge Management, the sole ownerof the Partnership’s i-units, during 2006 in lieu of cash distributions.

(2)         The Partnership retains an amount equal to2% of the i-unit distribution from the General Partner in respect of its2% general partner interest.

**9.**   COMMITMENTS,CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

***EnvironmentalLiabilities***

We are subject to federal and state laws andregulations relating to the protection of the environment. Environmental riskis inherent to liquid and natural gas pipeline operations and we could, attimes, be subject to environmental cleanup and enforcement actions. We managethis environmental risk through appropriate environmental policies andpractices to minimize any impact on the environment of our pipeline operations.

As of June 30, 2006 and December 31, 2005,we have recorded $3.3 million and $4.0 million, respectively, incurrent liabilities and $4.9 million and $4.8 million, respectively,in long-term liabilities, primarily to address remediation ofcontaminated sites, materials containing asbestos, management of hazardouswaste material disposal, and outstanding air quality measures for certain ofour liquids and natural gas assets.

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In April 2006, anatural gas release and fire near a valve site on our MidLa natural gastransmission pipeline in Concordia Parish, Louisiana, resulted in property andequipment damage in the area. We estimate our losses from this incident toapproximate $1 million, which we recognized in the second quarter of 2006.

***Legal Proceedings***

We are a participant invarious legal proceedings arising in the ordinary course of business. Some ofthese proceedings are covered, in whole or in part, by insurance. We believethat the outcome of all these proceedings will not, individually or in theaggregate, have a material adverse effect on our financial condition.

**10.**   FINANCIALINSTRUMENTS—COMMODITY PRICE RISK

Our net income and cashflows are subject to volatility stemming from changes in commodity prices ofnatural gas, natural gas liquids (“NGL” or “NGLs”), condensate andfractionation margins (the relative price differential between NGL sales andoffsetting natural gas purchases). This market price exposure exists within ourNatural Gas and Marketing segments. To mitigate the volatility of our cashflows, we use derivative financial instruments (i.e., futures, forwards, swaps,options and other financial instruments with similar characteristics) to managethe risks associated with market fluctuations in commodity prices. Based on ourrisk management policies, all of our derivative financial instruments areemployed in connection with an underlying asset, liability and/or forecastedtransaction and are not entered into with the objective of speculating oncommodity prices.

***Accounting Treatment***

All derivative financial instruments are recorded inthe consolidated financial statements at fair market value and are adjustedeach period for changes in the fair market value (“mark-to-market”).The fair market value of these derivative financial instruments reflects theestimated amounts that we would pay or receive, other than in a forced orliquidation sale, to terminate or close the contracts at the reporting date,taking into account the current unrealized losses or gains on open contracts.We use actively traded external market quotes and indices to valuesubstantially all of the financial instruments we utilize.

Under the guidance of Statement of FinancialAccounting Standards No. 133, *Accountingfor Derivative Transactions and Hedging Activities* (“SFAS No. 133”),if a derivative financial instrument does not qualify as a hedge or is notdesignated as a hedge, a change in the fair market value, both realized andunrealized, is recognized currently in our income statement as a derivativefair value gain (loss) and recorded in Cost of natural gas. Cash flow is onlyimpacted to the extent the actual derivative contract is settled by making orreceiving a payment to or from the counterparty or by making or receiving apayment for entering into a contract that exactly offsets the originalderivative contract. Typically, we settle our derivative contracts when thephysical transaction that underlies the derivative financial instrument occurs.

If a derivative financialinstrument qualifies and is designated as a cash flow hedge, a hedge of aforecasted transaction or future cash flows, any unrealized mark-to-market gainor loss is deferred in Accumulated other comprehensive income (“OCI”), acomponent of Partners’ Capital, until the underlying hedged transaction occurs.To the extent that the hedge instrument is effective in offsetting thetransaction being hedged, there is no impact to the income statement. Atinception and on a quarterly basis, we formally assess whether the hedgecontract is highly effective in offsetting changes in cash flows of hedgeditems. Any ineffective portion of a cash flow hedge’s change in fair marketvalue is recognized each period in earnings. Realized gains and losses onderivative financial instruments that are designated as hedges and qualify forhedge accounting are included in Cost of natural gas in the period the hedged 

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transactionoccurs. Gains and losses deferred in OCI related to cash flow hedges for whichhedge accounting has been discontinued, remain in OCI until the underlyingphysical transaction occurs unless it is probable that the forecastedtransaction will not occur by the end of the originally specified time periodor within an additional two-month period of time thereafter. Generally, ourpreference is for our derivative financial instruments to receive hedgeaccounting treatment whenever possible, to mitigate the non-cash earningsvolatility that arises under mark-to-market accounting treatment.To qualify for cash flow hedge accounting, very specific requirements must bemet in terms of hedge structure, hedge objective and hedge documentation.

***Non-Qualified Hedges***

Many of our derivative financial instruments qualifyfor hedge accounting treatment under the specific requirements of SFAS No. 133.However, we have four primary transaction types where the hedge structure doesnot meet the requirements to apply hedge accounting and, therefore, thesefinancial instruments are considered ‘non-qualified’ under SFAS No. 133.These non-qualified derivative financial instruments must be adjusted to theirfair market value, or marked-to-market, each period, with theincreases and decreases in fair value recorded as increases and decreases inCost of natural gas in our Consolidated Statements of Income. These mark-to-marketadjustments produce a degree of earnings volatility that can often be significantfrom period to period, but have no cash flow impact relative to changes inmarket prices. The cash flow impact occurs when the underlying physicaltransaction takes place in the future and an associated financial instrumentcontract settlement is made.

The four instances of non-qualified hedges are asfollows:

1.                **Transportation—**In our Marketing segment, when the pricingindex used for gas sales is different from the pricing index used for gaspurchases, we are exposed to relative changes in those two indices. By enteringinto a basis swap between those two indices, we can effectively lock in themargin on the combined gas purchase and gas sale, removing any market pricerisk on the physical transactions. Although this represents a sound economichedging strategy, these types of derivative transactions do not qualify forhedge accounting under SFAS No. 133, as the ultimate cash flow has notbeen fixed, only the margin.

2.                **Storage—**In our Marketing segment, when we use derivativefinancial instruments to hedge market spreads around our owned or contractedassets, such as our gas storage portfolio, the underlying forecastedtransaction may or may not occur in the same period as originally forecast.This can occur because we have the flexibility to make changes in theunderlying injection or withdrawal schedule, given changes in marketconditions. Therefore, these transactions do not qualify for cash flow hedgeaccounting treatment under SFAS No. 133, since the occurrence of thetransactions cannot be accurately forecast. Because the physical natural gas isrecorded at the lower of cost or market, timing differences can result when thederivative financial instrument is settled in a period that is different fromwhen the physical natural gas is sold. As a result, derivative financialinstruments associated with our natural gas storage activities can createvolatility in our earnings.

3.                **Natural Gas Collars—**In our Natural Gas segment, we hadpreviously entered into natural gas collars to hedge the sales price of naturalgas. The natural gas collars were based on a NYMEX price, while the physicalgas sales were based on a different index. To better align the index of thenatural gas collars with the index of the underlying sales, we de-designatedthe original cash flow hedging relationship with the intent ofcontemporaneously re-designating the natural gas collars as hedges offorecasted physical natural gas sales with a NYMEX pricing index to bettermatch the indices, which was a sound economic hedging strategy. However,because the fair value of these derivative instruments was a liability to us atre-designation, they are considered net written 

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options under SFAS No. 133and do not qualify for hedge accounting. These derivatives are being marked-to-market,with the changes in fair value from the date of de-designation recordedto earnings each period. As a result, our operating income will be subject togreater volatility due to movements in the prices of natural gas until theunderlying long-term transactions are settled.

4.                **Optional Natural Gas Processing Volumes—**In our Natural Gassegment we use derivative financial instruments to hedge the prices of NGLsassociated with some of the volumes produced from our natural gas processingactivities. Our natural gas contracts allow us the option of processing naturalgas when it is economical, and ceasing to do so when processing becomesuneconomic. We have entered into derivative financial instruments to fix thesales price of a portion of the NGLs that we produce at our discretion and tofix the related purchases of natural gas required for processing. Some of thesederivatives do not qualify for hedge accounting under SFAS No. 133 becausewe are unable to forecast the NGLs to be processed that underlie the derivativesince we have the option of processing or not processing as conditions warrant.As a result, our operating income will be subject to increased volatility dueto movements in the prices of NGLs until the underlying long-termtransactions are settled.

In each of the instances described above, theunderlying physical purchase, storage and sale of natural gas and NGLs areaccounted for on a historical cost basis rather than on the mark-to-marketbasis we utilize for the financial derivatives used to mitigate (hedge) thecommodity price risk associated with our storage and transportation assets.This difference in accounting (i.e.,the financial derivative is recorded at fair market values while the physicaltransaction is recorded at historical cost) can and has resulted involatility in our reported net income, even though the economic margin isessentially unchanged from the date the transactions were consummated.

Thefollowing table presents the unrealized gains and losses associated withchanges in the fair value of our commodity price derivatives, which arerecorded as an element of Cost of natural gas in our Consolidated Statements ofIncome and disclosed as a reconciling item on our Statements of Cash Flows:

|                                       | ** ** | **Three months ended  June 30,**                      | ** ** | **Six months ended  June 30,**                        | ** ** |
|---------------------------------------|------------|----------------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|
| ** **                            | ** ** | **     2006     ** | ** ** | **     2005     ** | ** ** | **     2006     ** | ** ** | **     2005     ** | ** ** |
| ** **                            | ** ** | **(in millions)**                                               | ** ** |
| Natural Gas segment                   |       |                                                                 |       |                                                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Ineffectiveness                       |       |                                                                 | $          | (0.1                                                                 | )          |   |   | $ | (1.8 | ) |   |   | $ | (0.1 | ) |   |   | $ | (2.0 | ) |   |   |
| Non-qualified hedges                  |       |                                                                 | (3.6       | )                                                                    |       |   | (2.9 | ) |   |   | (1.8 | ) |   |   | (11.1 | ) |   |   |
| Marketing                             |       |                                                                 |       |                                                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Non-qualified hedges                  |       |                                                                 | 5.4        |                                                                 |       |   | 3.9 |   |   |   | 31.3 |   |   |   | 5.3 |   |   |   |
| Discontinuance                        |       |                                                                 | —     |                                                                 |       |   | (9.0 | ) |   |   | — |   |   |   | (9.0 | ) |   |   |
| Derivative fair value gains  (losses) |       |                                                                 | $          | 1.7                                                                  |       |   |   | $ | (9.8 | ) |   |   | $ | 29.4 |   |   |   | $ | (16.8 | ) |   |   |

 

We record the change in fair value of our highlyeffective cash flow hedges in OCI until the derivative financial instrumentsare settled, at which time they are reclassified to earnings. Also included inOCI are unrecognized losses of approximately $6.3 million associated withderivative financial instruments that qualified for and were classified as cashflow hedges of forecasted transactions that were subsequently de-designated.These unrecognized losses are reclassified to earnings over the periods duringwhich the originally hedged forecasted transactions affect earnings. For thethree and six months ended June 30, 2006, we reclassified unrealizedlosses of $14.9 million and $39.7 million from OCI to Cost of natural gas onour Consolidated Statements of Income for the fair value of derivativefinancial instruments that were settled.

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Ourderivative financial instruments are included at their fair values in theConsolidated Statements of Financial Position as follows:

|                              | ** ** | **June 30,  2006** | ** ** | **December 31,  2005** | ** ** |
|------------------------------|------------|-------------------------|------------|-----------------------------|------------|
| ** **                   | ** ** | **(in millions)**  | ** ** |
| Other current assets         |       | $                       | 4.6        |                        |       | $ | 5.8 |   |   |
| Other assets, net            |       | 8.5                     |       |                        | 4.2        |   |   |
| Accounts payable and other   |       | (123.0                  | )          |                        | (129.2     | ) |   |
| Other long-term  liabilities |       | (219.9                  | )          |                        | (243.0     | ) |   |
|                              |       | $                       | (329.8     | )                           |       | $ | (362.2 | ) |   |

 

The decrease in our obligation associated withderivative activities is primarily due to the decline in current and forwardnatural gas prices from December 31, 2005 to June 30, 2006. ThePartnership’s portfolio of derivative financial instruments is largelycomprised of long-term fixed price sales and purchase agreements.

We do not requirecollateral or other security from the counterparties to our derivative financialinstruments, all of which were rated “BBB+” or better by the major creditrating agencies.

**11.**   SEGMENTINFORMATION

Our business is dividedinto operating segments, defined as components of the enterprise, about whichfinancial information is available and evaluated regularly by our ChiefOperating Decision Maker in deciding how resources are allocated andperformance is assessed.

Eachof our reportable segments is a business unit that offers different servicesand products that is managed separately, since each business segment requiresdifferent operating strategies. We have segregated our business activities intothree distinct operating segments:

·       Liquids;

·       NaturalGas; and

·       Marketing.

Thefollowing tables present certain financial information relating to our businesssegments:

|                                                 | ** ** | **As of and for the three months ended June 30, 2006** | ** ** |
|-------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------|------------|
| ** **                                      | ** ** | **Liquids**                                                                                              | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| ** **                                      | ** ** | **(in millions)**                                                                                   | ** ** |
| Total revenue                                   |       | $                                                                                                        | 124.9      |   |   | $ | 1,231.3 |   |   |   | $ | 667.6 |   |   |   | $ | — |   |   | $ | 2,023.8 |   |
| Less:  Intersegment revenue                     |       | —                                                                                                   |       |   | 557.8 |   |   |   | 41.3 |   |   |   | — |   |   | 599.1 |   |
| Operating revenue                               |       | 124.9                                                                                                    |       |   | 673.5 |   |   |   | 626.3 |   |   |   | — |   |   | 1,424.7 |   |
| Cost of natural  gas (Notes 5 and 10)           |       | —                                                                                                   |       |   | 566.9 |   |   |   | 618.7 |   |   |   | — |   |   | 1,185.6 |   |
| Operating and administrative                    |       | 35.1                                                                                                     |       |   | 50.0 |   |   |   | 1.5 |   |   |   | 0.7 |   |   | 87.3 |   |
| Power                                           |       | 24.2                                                                                                     |       |   | — |   |   |   | — |   |   |   | — |   |   | 24.2 |   |
| Depreciation and  amortization (Note 6)         |       | 15.9                                                                                                     |       |   | 17.9 |   |   |   | 0.1 |   |   |   | 0.1 |   |   | 34.0 |   |
| Operating income                                |       | 49.7                                                                                                     |       |   | 38.7 |   |   |   | 6.0 |   |   |   | (0.8 | ) |   | 93.6 |   |
| Interest expense                                |       | —                                                                                                   |       |   | — |   |   |   | — |   |   |   | (27.6 | ) |   | (27.6 | ) |
| Other income                                    |       | —                                                                                                   |       |   | — |   |   |   | — |   |   |   | 4.4 |   |   | 4.4 |   |
| Net income                                      |       | $                                                                                                        | 49.7       |   |   | $ | 38.7 |   |   |   | $ | 6.0 |   |   |   | $ | (24.0 | ) |   | $ | 70.4 |   |
| Capital  expenditures (excluding  acquisitions) |       | $                                                                                                        | 34.4       |   |   | $ | 148.0 |   |   |   | $ | 0.5 |   |   |   | $ | 3.6 |   |   | $ | 186.5 |   |

 

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|                                                 | ** ** | **As of and for the three months ended June 30, 2005** | ** ** |
|-------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------|------------|
| ** **                                      | ** ** | **Liquids**                                                                                              | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| ** **                                      | ** ** | **(in millions)**                                                                                   | ** ** |
| Total revenue                                   |       | $                                                                                                        | 102.5      |   |   | $ | 988.0 |   |   |   | $ | 802.1 |   |   |   | $ | — |   |   | $ | 1,892.6 |   |
| Less:  Intersegment revenue                     |       | —                                                                                                   |       |   | 526.7 |   |   |   | 33.2 |   |   |   | — |   |   | 559.9 |   |
| Operating revenue                               |       | 102.5                                                                                                    |       |   | 461.3 |   |   |   | 768.9 |   |   |   | — |   |   | 1,332.7 |   |
| Cost of natural  gas (Notes 5 and 10)           |       | —                                                                                                   |       |   | 379.5 |   |   |   | 770.9 |   |   |   | — |   |   | 1,150.4 |   |
| Operating and administrative                    |       | 37.5                                                                                                     |       |   | 40.9 |   |   |   | 0.9 |   |   |   | 1.1 |   |   | 80.4 |   |
| Power                                           |       | 17.2                                                                                                     |       |   | — |   |   |   | — |   |   |   | — |   |   | 17.2 |   |
| Depreciation and  amortization (Note 6)         |       | 17.7                                                                                                     |       |   | 16.2 |   |   |   | 0.2 |   |   |   | — |   |   | 34.1 |   |
| Operating income                                |       | 30.1                                                                                                     |       |   | 24.7 |   |   |   | (3.1 | ) |   |   | (1.1 | ) |   | 50.6 |   |
| Interest expense                                |       | —                                                                                                   |       |   | — |   |   |   | — |   |   |   | (25.6 | ) |   | (25.6 | ) |
| Other income                                    |       | —                                                                                                   |       |   | — |   |   |   | — |   |   |   | 0.7 |   |   | 0.7 |   |
| Net income                                      |       | $                                                                                                        | 30.1       |   |   | $ | 24.7 |   |   |   | $ | (3.1 | ) |   |   | $ | (26.0 | ) |   | $ | 25.7 |   |
| Capital  expenditures (excluding  acquisitions) |       | $                                                                                                        | 21.6       |   |   | $ | 78.6 |   |   |   | $ | — |   |   |   | $ | 1.6 |   |   | $ | 101.8 |   |

 

|                                                | ** ** | **As of and for the six months ended June 30, 2006** | ** ** |
|------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Liquids**                                                                                            | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                                                                 | ** ** |
| Total revenue                                  |       | $                                                                                                      | 247.5      |   |   | $ | 2,833.2 |   |   |   | $ | 1,634.0 |   |   |   | $ | — |   |   | $ | 4,714.7 |   |
| Less:  Intersegment revenue                    |       | —                                                                                                 |       |   | 1,288.7 |   |   |   | 112.7 |   |   |   | — |   |   | 1,401.4 |   |
| Operating revenue                              |       | 247.5                                                                                                  |       |   | 1,544.5 |   |   |   | 1,521.3 |   |   |   | — |   |   | 3,313.3 |   |
| Cost of natural  gas (Notes 5 and 10)          |       | —                                                                                                 |       |   | 1,340.4 |   |   |   | 1,492.9 |   |   |   | — |   |   | 2,833.3 |   |
| Operating and administrative                   |       | 63.7                                                                                                   |       |   | 93.7 |   |   |   | 2.6 |   |   |   | 1.2 |   |   | 161.2 |   |
| Power                                          |       | 50.5                                                                                                   |       |   | — |   |   |   | — |   |   |   | — |   |   | 50.5 |   |
| Depreciation and  amortization (Note 6)        |       | 31.8                                                                                                   |       |   | 34.5 |   |   |   | 0.2 |   |   |   | 0.2 |   |   | 66.7 |   |
| Operating income                               |       | 101.5                                                                                                  |       |   | 75.9 |   |   |   | 25.6 |   |   |   | (1.4 | ) |   | 201.6 |   |
| Interest expense                               |       | —                                                                                                 |       |   | — |   |   |   | — |   |   |   | (55.5 | ) |   | (55.5 | ) |
| Other income                                   |       | —                                                                                                 |       |   | — |   |   |   | — |   |   |   | 5.4 |   |   | 5.4 |   |
| Net income                                     |       | $                                                                                                      | 101.5      |   |   | $ | 75.9 |   |   |   | $ | 25.6 |   |   |   | $ | (51.5 | ) |   | $ | 151.5 |   |
| Total assets                                   |       | $                                                                                                      | 1,704.7    |   |   | $ | 2,421.6 |   |   |   | $ | 276.5 |   |   |   | $ | 85.1 |   |   | $ | 4,487.9 |   |
| Capital expenditures  (excluding acquisitions) |       | $                                                                                                      | 50.8       |   |   | $ | 229.1 |   |   |   | $ | 0.9 |   |   |   | $ | 4.4 |   |   | $ | 285.2 |   |

 

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|                                                | ** ** | **As of and for the six months ended June 30, 2005** | ** ** |
|------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Liquids**                                                                                            | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                                                                 | ** ** |
| Total revenue                                  |       | $                                                                                                      | 199.0      |   |   | $ | 1,912.6 |   |   |   | $ | 1,495.9 |   |   |   | $ | — |   |   | $ | 3,607.5 |   |
| Less:  Intersegment revenue                    |       | —                                                                                                 |       |   | 965.7 |   |   |   | 59.0 |   |   |   | — |   |   | 1,024.7 |   |
| Operating revenue                              |       | 199.0                                                                                                  |       |   | 946.9 |   |   |   | 1,436.9 |   |   |   | — |   |   | 2,582.8 |   |
| Cost of natural  gas (Notes 5 and 10)          |       | —                                                                                                 |       |   | 786.0 |   |   |   | 1,436.6 |   |   |   | — |   |   | 2,222.6 |   |
| Operating and administrative                   |       | 69.4                                                                                                   |       |   | 82.0 |   |   |   | 1.7 |   |   |   | 1.7 |   |   | 154.8 |   |
| Power                                          |       | 34.2                                                                                                   |       |   | — |   |   |   | — |   |   |   | — |   |   | 34.2 |   |
| Depreciation and  amortization (Note 6)        |       | 35.3                                                                                                   |       |   | 31.8 |   |   |   | 0.3 |   |   |   | — |   |   | 67.4 |   |
| Operating income                               |       | 60.1                                                                                                   |       |   | 47.1 |   |   |   | (1.7 | ) |   |   | (1.7 | ) |   | 103.8 |   |
| Interest expense                               |       | —                                                                                                 |       |   | — |   |   |   | — |   |   |   | (51.2 | ) |   | (51.2 | ) |
| Other income                                   |       | —                                                                                                 |       |   | — |   |   |   | — |   |   |   | 1.3 |   |   | 1.3 |   |
| Net income                                     |       | $                                                                                                      | 60.1       |   |   | $ | 47.1 |   |   |   | $ | (1.7 | ) |   |   | $ | (51.6 | ) |   | $ | 53.9 |   |
| Total assets                                   |       | $                                                                                                      | 1,670.8    |   |   | $ | 2,053.3 |   |   |   | $ | 280.6 |   |   |   | $ | 94.5 |   |   | $ | 4,099.2 |   |
| Capital expenditures  (excluding acquisitions) |       | $                                                                                                      | 34.7       |   |   | $ | 137.3 |   |   |   | $ | — |   |   |   | $ | 2.7 |   |   | $ | 174.7 |   |

 

**12.**   SUBSEQUENTEVENT

***Distribution to Partners***

On July 28, 2006, the Board of Directors ofEnbridge Management declared a distribution payable to our partners on August 14,2006. The distribution will be paid to unitholders of record as of August 4,2006, of our available cash of $68.1 million at June 30, 2006, or$0.925 per common unit. Of this distribution, $56.6 million will be paidin cash, $11.3 million will be distributed in i-units to our i-unitholderand $0.2 million will be retained from the General Partner in respect ofthis i-unit distribution.

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**Item 2.**                        Management’sDiscussion and Analysis of Financial Condition and Results of Operations

The following discussion of financial condition andresults of operations of Enbridge Energy Partners, L.P. should be readtogether with the consolidated financial statements and the notes in thisreport. The discussion in this section pertains to our unaudited consolidatedbalance sheets, statements of income, and statements of cash flows.

This report on Form 10-Qshould be read in conjunction with our annual report on Form 10-Kfor the year ended December 31, 2005.

**RESULTS OFOPERATIONS—OVERVIEW**

We provide servicesto our customers and returns for our unitholders primarily through thefollowing activities:

·       Interstatepipeline transportation and storage of crude oil and liquid petroleum;

·       Gathering,treating, processing and transportation of natural gas and natural gas liquids,or NGLs, through pipelines and related facilities; and

·       Providingsupply, transmission and sales services, including purchasing and sellingnatural gas and NGLs.

We conduct our business through three businesssegments: Liquids, Natural Gas and Marketing. These segments are strategicbusiness units established by senior management to facilitate the achievementof our long-term objectives, to aid in resource allocation decisions andto assess operational performance.

We primarily provide fee-based services to ourcustomers to minimize commodity price risks. However, in our natural gas andmarketing businesses, a portion of our earnings and cash flows are exposed tomovements in the prices of natural gas and NGLs. To substantially mitigate thisexposure and to provide stability to the Partnership’s cash flow, we enter intoderivative financial instrument transactions. Certain of these transactionsqualify for hedge accounting under Statement of Financial Accounting Standards No. 133,*Accounting for Derivative Transactions andHedging Activities* (“SFAS No. 133”); some however, must beaccounted for using the mark-to-market method of accounting andthis can expose our earnings to significant volatility.

Thefollowing table reflects our operating income by business segment and corporatecharges for the three and six month periods ended June 30, 2006 and 2005:

|                                          | ** ** | **Three months ended  June 30,** | ** ** | **Six months ended  June 30,** | ** ** |
|------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                               | ** ** | **   2006   **    | ** ** | **   2005   **  | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                               | ** ** | **(unaudited; in millions)**          | ** ** |
| **Operating Income**                | ** ** |                                            | ** ** | ** **                                    |       |   | ** ** | ** ** |   | ** ** | ** ** | ** ** | ** ** |
| Liquids                                  |       |                                            | $          | 49.7                                          |       |   |   | $ | 30.1 |   |   | 101.5 |   | $ | 60.1 |   |
| Natural Gas                              |       |                                            | 38.7       |                                          |       |   | 24.7 |   |   | 75.9 |   | 47.1 |   |
| Marketing                                |       |                                            | 6.0        |                                          |       |   | (3.1 | ) |   | 25.6 |   | (1.7 | ) |
| Corporate, operating and  administrative |       |                                            | (0.8       | )                                             |       |   | (1.1 | ) |   | (1.4 | ) | (1.7 | ) |
| **Total  Operating Income**              |       |                                            | 93.6       |                                          |       |   | 50.6 |   |   | 201.6 |   | 103.8 |   |
| Interest expense                         |       |                                            | (27.6      | )                                             |       |   | (25.6 | ) |   | (55.5 | ) | (51.2 | ) |
| Other income                             |       |                                            | 4.4        |                                          |       |   | 0.7 |   |   | 5.4 |   | 1.3 |   |
| **Net Income**                           |       |                                            | $          | 70.4                                          |       |   |   | $ | 25.7 |   |   | $ | 151.5 |   | $ | 53.9 |   |
|                                          |            |                                                 |            |                                               |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

16

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***Summary Analysis of Operating Results***

*Liquids*

Our Liquids segmentproduced operating income of $49.7 million and $101.5 million for the three andsix month periods ended June 30, 2006, a 65 percent increase and 69percent increase over the $30.1 million and $60.1 million earned in thecomparable periods in 2005. The following primary factors contributed to theincrease in operating income of our Liquids segment:

·       Highervolumes on our Lakehead system following completion of the repair and expansionof a major oil sands plant that was damaged by a fire in early January 2005;

·       Increaseddeliveries on our Mid-Continent system have resulted from greater demand byMidwest refineries for crude from the Gulf Coast region to meet the rise inconsumer demand for gasoline supplies during summer months;

·       Theannual index rate increase effective July 1, 2005, which increased ouraverage tariffs; and

·       Longer hauls on ourLakehead system.

*Natural Gas*

Operating incomefrom our Natural Gas segment grew 57 percent to $38.7 million and 61 percent to$75.9 million for the respective three and six month periods ended June 30,2006 over the comparable periods in 2005. The increased contribution of ourNatural Gas segment is primarily attributable to the following:

·       Highercrude oil and NGL prices in relation to natural gas prices contributed tofavorable operating results from our processing assets in addition to theexpanded processing capacity on ourAnadarko system;

·       Growth in average daily volumes on our majornatural gas systems stemming from additional wellhead supply contracts on theEast Texas and Anadarko systems; and

·       Continued strong drilling activity in the Anadarko Basin and East TexasBossier trend.

*Marketing*

Operating incomefrom our Marketing segment increased by $9.1 million and $27.3 million to $6.0million and $25.6 million for the three and six months ended June 30,2006, respectively, from operating losses of $3.1 million and $1.7 million forthe same periods in 2005. The increase in operating income of our Marketingsegment is predominantly the result of two factors:

·       Unrealized,non-cash mark-to-market gains for the three and six months ended June 30,2006 of $5.4 million and $31.3 million as compared with non-cash mark-to-marketlosses of $5.1 million and $3.7 million for the comparable periods in 2005. Thegains resulted from the change in market value of our derivative financialinstruments that do not qualify for hedge accounting;

·       Partially offsetting theunrealized mark-to-market gains is a non-cash charge of $1.7 million for thethree months and $9.7 million for the six months ended June 30, 2006,resulting from a lower of cost or market accounting adjustment to the costbasis of our natural gas inventory. The market price for natural gas in two ofour storage locations experienced further decreases during the quarter from theprices at which the inventory was purchased. We expect to recover a majority ofthis charge when the inventory is sold in future quarters.

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***Derivative Transactions and Hedging Activities***

We record all derivative financial instruments in theconsolidated financial statements at fair market value pursuant to therequirements of SFAS No. 133. For those derivative financial instrumentsthat do not qualify for hedge accounting, all changes in fair market value arerecorded through our Consolidated Statements of Income each period. The fairmarket value of these derivative financial instruments reflects the estimatedamounts that we would pay or receive, other than in a forced or liquidationsale, to terminate or close the contracts at the reporting date, taking intoaccount the current unrealized losses or gains on open contracts.

NGL prices, which tend to move in correlation withcrude oil prices, have continued to trend higher due to supply instability inthe crude oil market. As a result, during the three and six months ended June 30,2006, we experienced unrealized, non-cash mark-to-market losses in our NaturalGas segment. These non-cash mark-to-market losses primarily relate toderivative financial instruments associated with the sale of NGLs derived fromour processing activities that do not qualify for hedge accounting under SFAS No. 133.

The prices of natural gas were lower at June 30,2006 in relation to the prices at March 31, 2006 and December 31,2005, which resulted in unrealized, non-cash mark-to-market gains in ourMarketing segment for the three and six months ended June 30, 2006.

While the natural gas and NGL pricing environmentcontinues to remain volatile, the mark-to-market gains and losses created bythis volatility do not affect our cash flow. We expect these non-cash gains andlosses to be offset in future quarters as we settle the derivative financialinstruments and the underlying physical transactions.

Thefollowing table presents the unrealized, non-cash, mark-to-market gains andlosses by segment, associated with our derivative financial instruments for thethree and six month periods ended June 30, 2006 and 2005:

|                                       | ** ** | **Three months ended  June 30,** | ** ** | **Six months ended  June 30,** | ** ** |
|---------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                            | ** ** | **   2006   **    | ** ** | **   2005   **  | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                            | ** ** | **(in millions)**                          | ** ** |
| Natural Gas segment                   |       |                                            |       |                                          |       |   |   |   |   |   |   |   |   |
| Ineffectiveness                       |       |                                            | $          | (0.1                                          | )          |   |   | $ | (1.8 | ) |   | $ | (0.1 | ) | $ | (2.0 | ) |
| Non-qualified hedges                  |       |                                            | (3.6       | )                                             |       |   | (2.9 | ) |   | (1.8 | ) | (11.1 | ) |
| Marketing                             |       |                                            |       |                                          |       |   |   |   |   |   |   |   |   |
| Non-qualified hedges                  |       |                                            | 5.4        |                                          |       |   | 3.9 |   |   | 31.3 |   | 5.3 |   |
| Discontinuance                        |       |                                            | —     |                                          |       |   | (9.0 | ) |   | — |   | (9.0 | ) |
| Derivative fair value gains  (losses) |       |                                            | $          | 1.7                                           |       |   |   | $ | (9.8 | ) |   | $ | 29.4 |   | $ | (16.8 | ) |

 

In December 2005, wesettled natural gas collars representing derivative financial instruments onforecasted sales of 2,000 million British thermal units per day, or MMBtu/d, ofnatural gas through 2011. The settlement of these collars reduced the amount ofnon-cash losses reflected above in our Natural Gas segment at June 30,2006.

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**RESULTS OFOPERATIONS—BY SEGMENT**

***Liquids***

Thefollowing tables set forth the operating results and statistics of our Liquidssegment assets for the periods presented:

|                                            | ** ** | **Three months ended  June 30,** | ** ** | **Six months ended  June 30,** | ** ** |
|--------------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                                 | ** ** | **   2006   **    | ** ** | **   2005   **  | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                 | ** ** | **(unaudited; in millions)**          | ** ** |
| **Operating Results**                      | ** ** |                                            | ** ** | ** **                                    |       |   | ** ** | ** ** |   | ** ** | ** ** | ** ** | ** ** |
| Operating revenues                         |       |                                            | $          | 124.9                                         | ** ** |   |   | $ | 102.5 | ** ** |   | $ | 247.5 |   | $ | 199.0 |   |
| Operating and administrative               |       |                                            | 35.1       | ** **                                    |       |   | 37.5 | ** ** |   | 63.7 |   | 69.4 |   |
| Power                                      |       |                                            | 24.2       | ** **                                    |       |   | 17.2 | ** ** |   | 50.5 |   | 34.2 |   |
| Depreciation and  amortization             |       |                                            | 15.9       | ** **                                    |       |   | 17.7 | ** ** |   | 31.8 |   | 35.3 |   |
| Expenses                                   |       |                                            | 75.2       | ** **                                    |       |   | 72.4 | ** ** |   | 146.0 |   | 138.9 |   |
| **Operating Income**                       |       |                                            | $          | 49.7                                          | ** ** |   |   | $ | 30.1 | ** ** |   | $ | 101.5 |   | $ | 60.1 |   |
| **Operating  Statistics**                  | ** ** |                                            | ** ** | ** **                                    |       |   | ** ** | ** ** |   | ** ** | ** ** | ** ** | ** ** |
| **Lakehead system:**                       | ** ** |                                            | ** ** | ** **                                    |       |   | ** ** | ** ** |   | ** ** | ** ** | ** ** | ** ** |
| United States(1)                           |       |                                            | 1,186      | ** **                                    |       |   | 1,052 | ** ** |   | 1,173 |   | 1,031 |   |
| Province of Ontario(1)                     |       |                                            | 296        | ** **                                    |       |   | 277 | ** ** |   | 322 |   | 302 |   |
| **Total deliveries****(1)**                |       |                                            | 1,482      | ** **                                    |       |   | 1,329 | ** ** |   | 1,495 |   | 1,333 |   |
| **Barrel miles (billions)**                |       |                                            | 94         | ** **                                    |       |   | 84 | ** ** |   | 194 |   | 167 |   |
| **Average haul (miles)**                   |       |                                            | 699        | ** **                                    |       |   | 692 | ** ** |   | 719 |   | 691 |   |
| **Mid-Continent system deliveries****(1)** |       |                                            | 260        | ** **                                    |       |   | 226 | ** ** |   | 248 |   | 208 |   |
| **North  Dakota system deliveries****(1)** |       |                                            | 92         | ** **                                    |       |   | 89 | ** ** |   | 91 |   | 89 |   |

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(1)        Average barrels per day (“Bpd”) in thousands.

***Three months ended June 30, 2006 compared withthree months ended June 30, 2005***

Our Liquids segment accounted for $49.7 millionof operating income during the three months ended June 30, 2006,representing a $19.6 million increase over the same period in 2005. Thefavorable results of our Liquids segment assets reflect continuing growth inour transportation volumes while actively managing the costs of our services.The majority of this increase relates to significantly improved results on ourLakehead system, followed by growth on our Mid-Continent and North Dakotasystems.

Operating revenuesof our Liquids segment assets increased $22.4 million to $124.9 million for thesecond quarter of 2006 as compared with the $102.5 million earned in the secondquarter of 2005. As indicated in the table above, total delivery volumes of ourLiquids segment averaged 1.834 million Bpd in the second quarter of 2006,representing a 190,000 Bpd increase from the 1.644 million Bpd delivered in thesame period of 2005. This accounted for an increase in operating revenues ofapproximately $10.8 million. The increases in deliveries on our Liquidssystems have resulted from the following:

1.                Increasedcrude oil production in Western Canada primarily from the following sourcescontributed to greater deliveries on our Lakehead system:

·        Suncor,an oil sands producer in Alberta, Canada, experienced a fire at its upgradersite on January 4, 2005, which affected production for the majority of2005. In late September 2005, Suncor announced that repairs to itsupgrader site and an expansion were completed. Suncor’s production levels haveincreased since that time.

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·        Conventionalheavy crude oil and bitumen production have increased as existing and newfacilities add to capacity. Also, bitumen production was higher during thesecond quarter of 2006, as the nature of the cyclical steaming processused to extract it from the ground can cause production timing differencesduring the year.

2.                Deliverieson our Mid-Continent system began increasing during the second quarter 2006 asa result of greater demand for crude oil by Midwest refineries from suppliersin the Gulf Coast region. Seasonal consumer demand for gasoline suppliesrequires these refineries to run at or near capacity during the summer monthsto prevent supply shortages. Additionally, refinery procurement patterns haveshifted in favor of our Mid-Continent system to alleviate pipeline constraintsresulting from the increased demand for crude oil. As a result, deliveries onour Mid-Continent system increased 15 percent to 260,000 Bpd in the secondquarter of 2006 from the 226,000 Bpd delivered in the second quarter of 2005. Weexpect this condition to continue into the fourth quarter of 2006.

Contributing to the revenue growth of our Liquids segmentare the increases in the average tariffs on all three of our Liquids systemswhich resulted in higher operating revenue during the second quarter of 2006 ofapproximately $8.0 million. These tariff increases were mostly the result ofthe annual index rate increase of approximately 3.63% allowed by the FederalEnergy Regulatory Commission (“FERC”) effective July 1, 2005, on our basesystem tariffs. On our Lakehead system, new tariffs also went into effect on April 1,2006 for an adjustment on the Terrace expansion program surcharge due to lowerthan expected volumes moving on the Lakehead system, and new facilities inservice, which were not in effect during the second quarter of 2005.

Operating and administrative expenses for the Liquidssegment decreased $2.4 million for the second quarter of 2006, compared withthe same period in 2005. The decrease is primarily driven by lower oilmeasurement losses and property taxes, partially offset by higher workforcerelated costs and a provision for obsolete materials.

Oil measurementgains and losses occur as part of the normal operating conditions associatedwith our Liquids pipelines. The three types of oil measurement gains and lossesinclude:

·       physical,which occur through evaporation, shrinkage, differences in measurement betweenreceipt and delivery locations and other operational incidents;

·       degradation,which results in the pipelines from mixing at the interface between higherquality light crude oil and lower quality heavy crude oil; and

·       revaluation,which are a function of crude oil prices, the level of the carrier’s inventoryand the inventory positions of customers.

During the fourth quarter of 2005, we identifiedcertain operating conditions on connected third-party systems that werecontributing to higher levels of physical losses on our Lakehead system.Improvements to oil measurement processes have resulted in lower physicallosses during the second quarter of 2006. We expect these improvements to havea continuing positive impact on our oil measurement losses going forward. Weestimate that total oil measurement losses for 2006 will be approximately $5million, compared with $18 million in 2005, assuming crude oil prices remaincomparable to 2005 levels.

Power costs increased $7.0 million in the secondquarter of 2006, compared with the same period in 2005, primarily due to thehigher volumes transported on our Lakehead and Mid-Continent systems, inaddition to the higher millrates charged by our power suppliers. We haveexperienced a trend of increasing millrates from our power suppliers due tohigher natural gas costs.

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We completed adepreciation study of the Lakehead system in the first quarter of 2006 thatresulted in extending the composite remaining service life of the system assetsfrom 23 to 26 years. The effect of this change was a decrease to depreciationexpense of approximately $3.0 million for the three months endedJune 30, 2006. We expect the impact of the depreciation study to be areduction of depreciation expense by approximately $11 million for thefull year of 2006.

***Six months ended June 30, 2006 compared with thesix months ended June 30, 2005***

Our Liquids segmentaccounted for $101.5 million of operating income during the six monthsended June 30, 2006, representing a $41.4 million increase over the sameperiod in 2005. The components comprising our operatingincome changed during the first six months of 2006 as compared with the firstsix months of 2005 for the same reasons as noted above in the three-monthanalysis.

*Future ProspectsUpdate for Liquids*

Enbridge Inc. (“Enbridge”)and the Partnership continue to actively work with our customers to developtransportation options that will allow western Canadian crude oil access to newmarkets.

**PartnershipProjects**

In 2005, the Partnership and Enbridge announcedapproval of the 400,000 Bpd Southern Access expansion project, which receivedendorsement from the Canadian Association of Petroleum Producers (“CAPP”), atrade association that represents a large majority of the Lakehead system’scustomers. We are undertaking the U.S. portion of the expansion on our LakeheadSystem with the first stage to add approximately 44,000 Bpd of capacity in 2007and up to an additional 146,000 Bpd by early 2008. The first stage includes anew pipeline between Superior and Delavan, Wisconsin, along with pump stationenhancements upstream and downstream of this segment. The second stage of theexpansion project will provide additional upstream pumping capacity and a newpipeline from Delavan to Flanagan, Illinois, with completion expected in early2009. Completion of the total Southern Access expansion project will create a454-mile pipeline with approximately 400,000 Bpd of incremental capacityon our Lakehead System.

On March 16, 2006, the Federal Energy RegulatoryCommission (“FERC”) approved an Offer of Settlement with respect to tariffprinciples for the Southern Access expansion, which were negotiated with CAPP. InJuly 2006, the Partnership obtained support from its shippers and CAPP toincrease the diameter of the new pipeline segments of the project from 36inches, to which the previously negotiated tariff principles apply, up to 42inches. The incremental capital cost of the larger diameter pipe is currentlyestimated at approximately $157 million, bringing the total estimated cost ofthe Partnership’s portion of the project to approximately $1.3 billion. Thelarger diameter will not provide increased capacity in the near term but doesincrease the ultimate capacity of the line from 800,000 Bpd to 1,200,000 Bpdwith only minor expenditures for additional pumping. This places thePartnership in a favorable position to secure future expansion opportunitiesfor the Lakehead system. The Partnership will defer any return on theincremental capital until the additional capacity is required by shippers (seediscussion of Alberta Clipper project below). In the interim, shippers willabsorb all the incremental operating costs of the larger diameter line but willbenefit from reduced power costs at higher throughput levels. Fieldwork hascommenced on the project and pipe has been ordered to ensure full completion inearly 2009.

Based on forecasts of oil sands production growthprepared by Enbridge, and also by CAPP, the Partnership believes that therewill be a need for additional export pipeline capacity out of Western Canadaover and above projects which have already received shipper support. Based onthis analysis, and interest expressed by shippers, Enbridge and the Partnershipare planning to develop the Alberta Clipper project. This project will involveconstruction of a 36-inch diameter heavy crude line from Hardisty, Albertato Superior, Wisconsin in conjunction with additional pumping power applied tothe new 

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42-inch pipe fromSuperior to Flanagan, at a total cost of approximately $1.8 billion in 2006dollars, excluding the approximate cost of $157 million to “prebuild” SouthernAccess to 42 inches as discussed above. The Partnership’s share of this cost isestimated at approximately $700 million.

Alberta Clipper was originally planned to be acontract carrier pipeline based on interest expressed by selected shippers inproviding throughput commitments in return for assured access to capacity. Basedon discussions with a broader group of shippers the preference is for AlbertaClipper to be a common carrier line fully integrated with the Enbridge/Lakehead mainline systems for tolling purposes, provided that it can bedeveloped on a timely basis. Depending on the timing of other export capacityprojects, Alberta Clipper could be required to be in service between 2009 and2011. To maintain the option to achieve an in-service date in the fourthquarter of 2009, Enbridge and the Partnership will seek to reach agreement withshippers on the project terms in time to permit filing of regulatoryapplications before the end of 2006.

Based on the support received from our customers, weexpect to proceed with the previously announced North Dakota system expansion.This expansion will add approximately 30,000 Bpd of mainline throughputcapacity and expand the system’s feeder segment at an estimated cost of$70 million. The expansion is supported by increasing crude oil productionfrom the Williston Basin in Montana and North Dakota and is expected to becompleted in the latter half of 2007.

The Partnership continuesto experience strong interest from customers in securing access to long termcontract storage capacity at its Cushing, Oklahoma terminal. During the secondquarter commitments were obtained and construction activities were initiatedfor a further 1.7 million barrels of storage capacity at an expected cost ofapproximately $35 million. This will bring the total capacity of the terminalto approximately 16.9 million barrels of which approximately 1.5 million isrequired as operational tankage to support the Partnership’s Mid-Continentliquids pipeline systems, and the balance is available for contract.

**Enbridgeand Other Projects**

During the first quarter of 2006, Enbridge completedthe reversal of its Spearhead Pipeline that now flows from Chicago, Illinois toCushing, Oklahoma, with a capacity of 125,000 Bpd. In March 2006, thefirst western Canadian crude oil was delivered through this system into themajor oil hub at Cushing. We expect to benefit from the reversal of theSpearhead pipeline as western Canadian crude oil will be carried on ourLakehead system as far as Chicago, and then transferred to the Spearheadpipeline.

In April 2006, ExxonMobil announced it hadcompleted the reversal of two of its crude oil pipelines allowing up to 66,000Bpd of Canadian crude oil to flow from the U.S. Midwest to the U.S. Gulf Coast.The combined reversed pipeline is linked to our Lakehead system at Chicago viathe Mustang Pipe Line Partners system to Patoka, Illinois. The Mustang PipeLine Partners system is 30% owned by an affiliate of Enbridge. ExxonMobil hasreceived firm commitments from Canadian shippers for an average of 50,000 Bpdof capacity on the lines from Patoka, to Nederland, Texas for the next fiveyears. The connection of our Lakehead system with this new market should alsosupport increased throughput on our Lakehead system; however, the reversedExxonMobil system will also be capable of transporting western Canadian crudeoil moved via other competing pipelines into the Patoka market.

In July 2006, Enbridge announced that it receivedsupport from shippers and CAPP for its 36-inch diameter Southern AccessExtension pipeline from Flanagan, Illinois to Patoka, Illinois. The extensionwill broaden the reach of the Enbridge/Lakehead mainline system to incrementalmarkets accessible from the Patoka hub. The project will be undertaken byEnbridge, however, it will benefit the Partnership through incremental volumesmoving through the Lakehead system to reach this extension. The Southern AccessExtension will be integrated with the Lakehead system for tolling purposes on adistance-based rolled-in basis, with no toll impact on the Lakehead systemrevenue. Enbridge plans to file the tolling methodology with the FERC duringthe third quarter.

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In July 2006,Enbridge announced a successful open season on its Southern Lights diluentpipeline from Chicago, Illinois to Edmonton, Alberta. The Southern Lightspipeline responds to interest from a number of western Canadian producers toincrease the availability of diluent in Alberta. Diluent is required totransport the heavy oil and bitumen being produced in increasing volumes fromthe Alberta oil sands. The project will require approval of the Board ofDirectors of Enbridge Energy Management, L.L.C. (“Enbridge Management”) forexchange of a 156-mile section of pipeline we own for a similar sectionof a new pipeline to be constructed as part of the project. We expect tobenefit from increased heavy crude shipments, which will be facilitated by thediluent line. In addition, this project involves a reconfiguration of thePartnership’s light crude mainline system which will provide an additional30,000 to 50,000 Bpd of effective capacity at no cost to us. Once this capacityis utilized it will generate additional transportation revenue for us.

Shippers have indicatedinterest to Enbridge in development of additional pipeline capacity totransport Canadian crude oil to the U.S. Gulf Coast, including the potentialfor a direct line from Alberta to the Gulf Coast. Enbridge is examining anumber of alternatives to respond to this interest, including alternatives thatwould extend off our Lakehead system, utilizing either existing pipelines whichcould be connected and reversed, or newly constructed extensions. Thesealternatives would complement our Lakehead system and support its expansion. Enbridgehas indicated that a direct line would require a minimum of 400,000 Bpd ofthroughput commitments to be economic, and could not be in service before 2011.A direct line, if developed by Enbridge or any other party, would compete withour Lakehead system.

***Natural Gas***

Thefollowing tables set forth the operating results of our Natural Gas segmentassets and average daily volumes of our major systems in MMBtu/d for theperiods presented: 

|                                    | ** ** | **Three months ended  June 30,** | ** ** | **Six months ended  June 30,** | ** ** |
|------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                         | ** ** | **2006**                                        | ** ** | **2005**                                      | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                         | ** ** | **(unaudited; in millions)**          | ** ** |
| **Operating Results**              |       |                                            |       |                                          |       |   |   |   |   |
| Operating revenues                 |       | $                                               | 673.5      |                                          | $          | 461.3 |   | $ | 1,544.5 |   | $ | 946.9 |   |
| Cost of natural gas                |       | 566.9                                           |       | 379.5                                         |       | 1,340.4 |   | 786.0 |   |
| Operating and  administrative      |       | 50.0                                            |       | 40.9                                          |       | 93.7 |   | 82.0 |   |
| Depreciation and amortization      |       | 17.9                                            |       | 16.2                                          |       | 34.5 |   | 31.8 |   |
| Operating expenses                 |       | 634.8                                           |       | 436.6                                         |       | 1,468.6 |   | 899.8 |   |
| **Operating Income**               |       | $                                               | 38.7       |                                          | $          | 24.7 |   | $ | 75.9 |   | $ | 47.1 |   |
| **Operating Statistics (MMBtu/d)** | ** ** | ** **                                      | ** ** | ** **                                    | ** ** | ** ** | ** ** | ** ** | ** ** |
| East Texas(1)                      |       | 1,012,000                                       |       | 833,000                                       |       | 966,000 |   | 810,000 |   |
| Anadarko                           |       | 568,000                                         |       | 478,000                                       |       | 565,000 |   | 465,000 |   |
| North Texas                        |       | 283,000                                         |       | 260,000                                       |       | 281,000 |   | 262,000 |   |
| South Texas(1)                     |       | —                                          |       | 34,000                                        |       | — |   | 36,000 |   |
| UTOS                               |       | 188,000                                         |       | 191,000                                       |       | 193,000 |   | 194,000 |   |
| MidLa                              |       | 131,000                                         |       | 107,000                                       |       | 107,000 |   | 106,000 |   |
| AlaTenn                            |       | 34,000                                          |       | 53,000                                        |       | 44,000 |   | 68,000 |   |
| KPC                                |       | 27,000                                          |       | 19,000                                        |       | 37,000 |   | 39,000 |   |
| Bamagas                            |       | 83,000                                          |       | 9,000                                         |       | 60,000 |   | 11,000 |   |
| Other major intrastates            |       | 153,000                                         |       | 209,000                                       |       | 155,000 |   | 215,000 |   |
| Total                              |       | 2,479,000                                       |       | 2,193,000                                     |       | 2,408,000 |   | 2,206,000 |   |

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(1)        We sold theSouth Texas assets and a sour gas system in East Texas in December 2005,which had a combined average daily volume for the three and six months ended June 30,2005 of approximately 50,000 and 56,000 MMBtu/d, respectively.

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***Three months ended June 30, 2006 compared withthree months ended June 30, 2005***

Our Natural Gas segment produced $38.7 million ofoperating income in the second quarter of 2006, an increase of $14.0 millionfrom the $24.7 million of operating income generated in the correspondingperiod of 2005. The increase in operating income is primarily attributable tofavorable commodity prices which contributed to higher revenue generated by ourprocessing assets in excess of the cost we incur for natural gas. Additionally,operating income was higher due to volume increases on each of our majorsystems resulting from additional wellhead supply contracts and the expansionof our transportation and processing capacity.

Average daily volumes on our major natural gas systemswere up 13% in the second quarter of 2006, compared with the correspondingperiod in 2005. We have continued to experience volume growth in the basinsserved by our natural gas assets as a result of additional wellhead supplycontracts, predominantly on our East Texas, North Texas and Anadarko systems. Drillingactivity continues to increase in the Anadarko Basin, Bossier Trend and BarnettShale areas served by our systems. Also contributing to the increase in volumesis an 80-mile pipeline we acquired in April 2006 that iscomplimentary to our existing East Texas system and provided approximately80,000 MMBtu/d of incremental volume. Additionally, completion of the EastTexas expansion project in late June 2005 contributed to the growth involumes for the three months ended June 30, 2006. We expect increasingvolumes on our major natural gas systems to result from our continuinginvestments to expand the capacity of our systems.

Unique circumstances during the second quarter of2006, resulting from instability in the crude oil market created an operatingenvironment whereby NGL prices, which tend to move in correlation with crudeoil prices, were trending higher while natural gas prices were declining. As aresult of this pricing environment, the revenue generated by our processingassets less the cost of natural gas purchased for processing was greater thanthe amounts we realized in the comparable period of 2005. A variable element ofthe Natural Gas segment’s operating income is derived from keep-wholeprocessing of natural gas. Operating income derived from our keep-wholeprocessing for the three months ended June 30, 2006, was approximately$17.4*** ***million compared with$6.4 million for the same period in 2005. We anticipate the operatingresults of our processing activities to remain favorable to the extent naturalgas prices remain low relative to NGL and crude oil prices.

A portion of our Natural Gas segment is exposed tocommodity price risks associated with percent of proceeds or percentage ofindex contracts that we negotiate with producers. Under the terms of thesecontracts, we retain a portion of the natural gas and NGLs we process inexchange for providing these producers with our services. In order to protectour unitholders from the volatility in cash flows that can result fromfluctuations in commodity prices, we enter into derivative financialinstruments to fix the sales price of the natural gas and NGLs we anticipatereceiving under the terms of these contracts. As a result of entering intothese derivative financial instruments, we have largely fixed the amount ofcash that we will receive in the future when we sell the processed natural gasand NGLs, although the market price of these commodities will continue tofluctuate during that time. Another significant portion of the revenue wereceive is derived from fees charged for gathering and treating of natural gasvolumes and other related services which is not directly dependent on commodityprices.

Operating income of our Natural Gas segment for thesecond quarter of 2006 includes unrealized non-cash, mark-to-market net lossesof $3.7 million, including $0.1 million of losses due to ineffectiveness. Inthe second quarter of 2005, our operating income was reduced by $4.7 million ofunrealized, non-cash, market-to-market losses that we incurred. The non-cashmark-to-market losses in 2006 are primarily derived from our derivativefinancial instruments that do not qualify for hedge accounting treatment underSFAS No. 133. We expect the net mark-to-market gains and losses to beoffset when the related physical transactions are settled (refer also to thediscussions included in Note 4 of Item 1. Financial Statements, 

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above and below underDerivative Activities, and Item 3. Quantitative and Qualitative DisclosuresAbout Market Risk).

The positive growth in our natural gas and NGLgathering, processing and transportation volumes for the second quarter of 2006was partially offset by increases in operating costs that are mostly variablewith volumes. The increase in operating and administrative costs isattributable to the continuing growth and expansion of our natural gas systems.As a result of the increase in volumes and the physical growth of our majorsystems, we have experienced an increase in workforce related costs associatedwith the operation of these assets. Workforce related costs have also increasedas a result of the expansion projects we are constructing to extend the servicecapability of our existing systems. Additionally, repair and maintenance costswere higher due to work performed during the quarter, including compressor andpump repairs.

We expect workforcerelated costs to continue increasing as a result of the large number of pipelineexpansions being performed in our industry that are causing competitiveconstraints across the United States. Our ability to attract and retain theresources necessary to complete our expansion projects may be affected by theseconstraints in the future causing additional increases in workforce relatedcost during the remainder of 2006.

***Six months ended June 30, 2006 compared with sixmonths ended June 30, 2005***

Our Natural Gas segment produced $75.9 million ofoperating income in the first six months of 2006, an increase of $28.8 millionfrom the $47.1 million of operating income generated in the correspondingperiod of 2005.

Average daily volumes on our major natural gas systemsincreased 9.2%, or approximately 202,000 MMBtu/d, for the six months ended June 30,2006, compared with the corresponding period in 2005. The increase in volumesis consistent with the reasons cited above in our three-month analysis.

As previously noted under our three-month analysis, aportion of our Natural Gas segment’s operating income is derived fromprocessing of natural gas under keep-whole arrangements. Operating incomederived from our keep-whole processing increased to approximately $27.6million for the six months ended June 30, 2006, compared with$10.5 million for the same period in 2005 for the same reasons discussedabove in our three-month analysis.

Operating income of our Natural Gas segment for thefirst six months of 2006 includes non-cash, mark-to-market net losses of $1.9million, including $0.1 million of losses due to ineffectiveness. In the firstsix months of 2005, our operating income was reduced by the $13.1 million ofnon-cash, market-to-market losses that we incurred, including $2.0 million oflosses due to ineffectiveness. The non-cash mark-to-market net losses in 2006are primarily derived from our derivative financial instruments that do notqualify for hedge accounting treatment under SFAS No. 133 as discussedabove under our three-month analysis (refer also to the discussions included inNote 4 of Item 1. Financial Statements, below under Derivative Activities, andItem 3. Quantitative and Qualitative Disclosures About Market Risk).

Operating andadministrative costs associated with our Natural Gas segment were$11.7 million greater for the six months ended June 30, 2006, thanfor the same period in 2005. The increase in operating and administrative costsof our Natural Gas segment is for the same reasons discussed above in ourthree-month analysis.

*Future ProspectsUpdate for Natural Gas*

We continue to assess various acquisition andexpansion opportunities to pursue our strategy for growth. The market foracquiring energy transportation assets continues to remain active andsignificant competition among prospective acquirers of assets persists. While weremain committed to making accretive acquisitions in or near areas where wealready operate or have a competitive advantage, we will 

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continue to focus ourefforts primarily on development of our existing pipeline systems. Although oneof our objectives is to grow our natural gas business through acquisitions, wemay and have pursued opportunities to divest any non-strategic natural gasassets as conditions warrant.

Results of our natural gas gathering and processingbusiness depend upon the drilling activities of natural gas producers in theareas we serve. During the first six months of 2006, increased drilling in theareas where our gathering systems are located has continued to contribute toour volume growth. We expect the growth trend in these areas to continue in thefuture as indicated by third-party production forecasts and the robust drillingrig counts in the areas served by our systems.

In the first six months of 2006, we completed anexpansion of our existing Zybach processing facility to a capacity of 150million cubic feet per day, or MMcf/d, of natural gas from the initial capacityof approximately 105 MMcf/d when we placed the plant in service in April 2005.We are continuing to make progress in constructing additional processingcapacity and field compression to accommodate the volume growth on the Anadarkosystem. We expect to place the additional processing capacity and fieldcompression in service in early 2007.

In the East Texasregion, we initiated construction on several projects in the first six monthsof 2006 to increase our gathering and treating infrastructure and market accesscapability. These projects continue to progress according to schedule andinclude:

·       A36-inch diameter intrastate pipeline from Bethel, Texas to Orange County,Texas with capacity of approximately 700 MMcf/d, to be completed in stagesthroughout 2007. The new line will provide service to a number of majorindustrial and power companies in Southeast Texas and will cross a number ofinterstate pipelines.

·       A200 MMcf/d treating facility to be built near Marquez, Texas will be connectedto the 36-inch diameter intrastate pipeline via a new 24-inchdiameter pipeline, to be completed in early 2007.

·       Anumber of upstream facilities, including gathering pipelines to tie existingfacilities into the new intrastate pipeline, will also be completed in early2007.

When fully operational in late 2007, the new assetswill be an additional source of stable cash flow for us. We continue to evaluate other projects that couldfurther integrate our major Texas-centered pipeline systems.

Although these projects continue to progress accordingto schedule, we expect the costs associated with completing the intrastatepipeline from Bethel, Texas to Orange County, Texas will exceed our initialestimates. Increased labor and construction costs are the primary factorscontributing to the additional cost. We currently anticipate the expansionproject will cost approximately $610 million.

In the third quarter of 2006 we expect that the linkbetween our North Texas and East Texas systems will be fully operational. Thecompletion of this connection will increase the utilization of the 500 MMcf/dintrastate pipeline we placed in service in June 2005 on our East Texas systemby providing customers of our North Texas system with additional market access.

In the third quarter we also anticipate completing theconstruction of the Henderson natural gas processing facility on our East Texassystem with a capacity of 125 MMcf/d. We expect the addition of this processingfacility to contribute to the favorable return we are experiencing on our otherprocessing assets.

In December 2005,Calpine Corporation (“Calpine”) and many of its subsidiaries, including thesubsidiary that owns the two utility plants served by our Bamagas system, filedvoluntarily petitions to restructure under Chapter 11 of the United StatesBankruptcy Code. In April 2006, Calpine announced its intent to sellapproximately 20 of its non-core and non-strategic power plants, although theplants to be sold have not been announced. Calpine has continued to performunder the terms of its agreement with 

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Bamagasand we remain confident that any losses we may incur with respect to Calpine’sbankruptcy will be minimal. We continue to monitor the Calpine bankruptcyproceedings and will recognize any losses that may result when it becomesevident that a loss has been incurred.

***Marketing***

Thefollowing table sets forth the operating results for the Marketing segmentassets for the periods presented:

|                                | ** ** | **Three months ended  June 30,**          | ** ** | **Six months ended  June 30,**            | ** ** |
|--------------------------------|------------|----------------------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                     | ** ** | **    2006    ** | ** ** | **    2005    ** | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                     | ** ** | **(unaudited; in millions)**                   | ** ** |
| Operating revenues             |       |                                                     | $          | 626.3                                                    |       |   |   | $ | 768.9 |   |   | $ | 1,521.3 |   | $ | 1,436.9 |   |
| Cost of natural  gas           |       |                                                     | 618.7      |                                                     |       |   | 770.9 |   |   | 1,492.9 |   | 1,436.6 |   |
| Operating and administrative   |       |                                                     | 1.5        |                                                     |       |   | 0.9 |   |   | 2.6 |   | 1.7 |   |
| Depreciation and  amortization |       |                                                     | 0.1        |                                                     |       |   | 0.2 |   |   | 0.2 |   | 0.3 |   |
| Expenses                       |       |                                                     | 620.3      |                                                     |       |   | 772.0 |   |   | 1,495.7 |   | 1,438.6 |   |
| **Operating  Income (loss)**   |       |                                                     | $          | 6.0                                                      |       |   |   | $ | (3.1 | ) |   | $ | 25.6 |   | $ | (1.7 | ) |

 

***Three months ended June 30, 2006 compared withthree months ended June 30, 2005***

A majority of the operating income of our Marketingsegment is derived from selling natural gas received from producers on ourNatural Gas segment pipeline assets to customers who need natural gas. Amajority of the natural gas we purchase is produced in Texas markets where wehave limited physical access to the primary interstate pipeline delivery points,or hubs such as Waha, Texas and the Houston Ship Channel. As a result, ourMarketing business must use third-party pipelines to transport the natural gasto these markets where it can be sold to our customers. However, physicalpipeline constraints often require our Marketing business to transport naturalgas to alternate market points. Under these circumstances, our Marketingsegment will sell the purchased gas at a pricing index that is different fromthe pricing index at which the gas was purchased. This creates a price exposurethat arises from the relative difference in natural gas prices between thecontracted index at which the natural gas is purchased and the index underwhich it is sold, otherwise known as the “spread.” The spread can vary significantlydue to local supply and demand factors. Wherever possible, this pricingexposure is economically hedged using derivative financial instruments.However, the structure of these economic hedges often precludes our use ofhedge accounting under the requirements of SFAS No. 133, which can createvolatility in the operating results of our Marketing segment.

To ensure that we have access to primary pipelinedelivery points, we often enter into firm transportation agreements oninterstate and intrastate pipelines. To offset the demand charges associatedwith these firm transportation contracts, we look for market conditions thatallow us to lock in the price differential or spread between the pipelinereceipt point and pipeline delivery point. This allows our Marketing businessto lock in a fixed sales margin inclusive of pipeline demand charges. Weaccomplish this by transacting basis swaps between the index where the naturalgas is purchased and the index where the natural gas is sold. By transacting a basisswap between those two indices, we can effectively lock in a margin on thecombined natural gas purchase and the natural gas sale, mitigating the demandcharges on firm transportation agreements and limiting the Partnership’sexposure to cash flow volatility that could arise in markets where the firmtransportation becomes uneconomic. However, the structure of these transactionsprecludes our use of hedge accounting under the requirements of SFASNo. 133, which can create volatility in the operating results of ourMarketing segment.

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In addition to natural gas basis swaps, we contractfor storage to assist balancing natural gas supply and end use market sales. Inorder to mitigate the absolute price differential between the cost of injectednatural gas and withdrawn natural gas, as well as storage fees, the injectionand withdrawal price differential, or “spread,” is hedged by buying fixed priceswaps for the forecasted injection periods and selling fixed price swaps forthe forecasted withdrawal periods. When the injection and withdrawal spreadincreases or decreases in value as a result of market price movements, we canearn additional profit through the optimization of those hedges in both theforward and daily markets. Although each of these hedge strategies are soundeconomic hedging techniques, these types of financial transactions do notqualify for hedge accounting under the SFAS No. 133 guidelines. As such,the non-qualified hedges are accounted for on a mark-to-marketbasis, and the periodic change in their market value, although non-cash, willimpact the income statement.

In the second quarter of 2006, the operating income ofour Marketing segment increased $9.1 million to $6.0 million, from a lossof $3.1 million for the corresponding period in 2005. Included inoperating income for the second quarter of 2006 are unrealized, non-cash,mark-to-market gains of approximately $5.4 million as compared with unrealizedmark-to-market losses of $5.1 million for the comparable period in 2005associated with derivative financial instruments that do not qualify for hedgeaccounting treatment under SFAS No. 133. In the second quarter of 2005, werecognized approximately $9.0 million of losses for the discontinuance of hedgeaccounting for derivative financial instruments associated with forecastedtransactions that we determined were not probable of occurring (refer also tothe discussion included below under Derivative Activities, Note 4 ofItem 1. Financial Statements, and Item 3. Quantitative andQualitative Disclosures About Market Risk).

Partially offsetting themark-to-market gains is a non-cash charge of $1.7 million to adjust the costbasis of our natural gas inventory to fair market value at June 30, 2006.Natural gas prices as published by Gas Daily for Henry Hub were approximately $6.99per million British thermal units, or MMBtu, at March 31, 2006, which haddeclined to $6.09 per MMBtu at June 30, 2006. As a result of thisnear-term decline in the price of natural gas at our storage locations from March 31,2006 to June 30, 2006, the weighted average cost of our natural gasinventory at June 30, 2006, exceeded the market price of natural gas byapproximately $1.7 million. As a result of this decline, we reduced the costbasis of our inventory to fair market value at June 30, 2006 by recordinga non-cash charge for $1.7 million. Due to our hedging structures, we expectthat a majority of this charge will be offset by future financial and physicaltransactions that will settle at the time the natural gas inventory is sold.

***Six months ended June 30, 2006 compared with sixmonths ended June 30, 2005***

In the first six months of 2006, the operating incomeof our Marketing segment increased $27.3 million to $25.6 million, from aloss of $1.7 million for the corresponding period in 2005. Included inoperating income for the first six months of 2006 are unrealized, non-cash,mark-to-market gains of approximately $31.3 million associated with derivativefinancial instruments that do not qualify for hedge accounting treatment underSFAS No. 133, as compared with unrealized mark-to-market losses of $3.7million for the comparable period in 2005. These mark-to-market gains areprimarily driven by the decline in natural gas prices since December 31,2005, as discussed above in our three-month analysis.

Partially offsetting themark-to-market gains is a non-cash loss of $9.7 million attributable toreducing the cost basis of our natural gas inventory to fair market value.Natural gas prices as published by Gas Daily for Henry Hub were approximately$10.08 per MMBtu at December 31, 2005, which had declined to $6.09 perMMBtu at June 30, 2006. As a result of the decline in the price of naturalgas from December 31, 2005 to June 30, 2006, we recorded chargestotaling $9.7 million during the six months ended June 30, 2006 to reducethe cost basis of our inventory to fair market value. Due to our hedgingstructures, we expect that a majority of these charges will be offset by futurefinancial transactions that will settle at the time the natural gas inventoryis sold.

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***Corporate***

Interest expense was $27.6 million and $55.5 millionfor the three and six months ended June 30, 2006, respectively, comparedwith $25.6 million and $51.2 million for the corresponding period in 2005.The increase is the result of higher debt balances and weighted averageinterest rates, partially offset by interest capitalized on our constructionprojects. Our weighted average rates of interest were approximately 5.86% and6.08% during the three and six months ended June 30, 2006, respectively,compared with approximately 5.72% and 5.86% during the corresponding periods in2005.

Included in other income for the three and six monthsended June 30, 2006, is $4.5 million that we received as settlement for aninsurance claim that we filed in connection with an interruption to theoperations of our Lakehead system resulting from a fire that occurred at Suncor’supgrader site in January 2005.

The Partnership is not ataxable entity for U.S. federal income tax purposes and historically has notbeen a taxable entity for state income tax purposes. Federal and state incometaxes on partnership taxable income were both borne directly by the unitholderswith no entity level tax on the Partnership. In May 2006, the State ofTexas enacted substantial changes to its tax structure beginning in 2007 byimposing a new tax based upon modified gross revenue referred to as the “MarginTax.”  We determined the “Margin Tax” tobe an income tax as defined under Statement of Financial Accounting Standards No. 109,*Accounting for Income Taxes*(“SFAS No. 109”).Our initial accounting for the enactment of this income tax did not materiallyaffect our results of operation, financial condition or cash flows.

**LIQUIDITY ANDCAPITAL RESOURCES**

***General***

We believe that our ability to generate cash flow, inaddition to our access to capital markets, is sufficient to meet the demands ofour current and future operating growth and investment needs. Our primary cashrequirements consist of normal operating expenses, maintenance and expansioncapital expenditures, debt service payments, distributions to partners,acquisitions of new assets or businesses, and payments associated with ourderivative transactions. Short-term cash requirements, such as operatingexpenses, maintenance capital expenditures and quarterly distributions topartners, are expected to be funded from our operating cash flows. Marginrequirements associated with our derivative transactions are generallysupported by letters of credit issued under our Credit Facility. We expect tofund long-term cash requirements for expansion projects and acquisitionsfrom several sources, including cash flows from operating activities,borrowings under our commercial paper program, our credit facilities, and theissuance of additional equity and debt securities. Our ability to completefuture debt and equity offerings and the timing of any such offerings willdepend on various factors, including prevailing market conditions, interestrates, our financial condition and credit rating at the time.

During 2005, we shiftedour business strategy to an emphasis on developing and expanding our existingLiquids and Natural Gas businesses with less focus on acquisitions. Theinternal growth projects we have planned for our Natural Gas business (seeNatural Gas segment—Future Prospects), coupled with the Southern Access expansionon our Lakehead system (see Liquids segment—Future Prospects), will requiresignificant expenditures of capital over the next several years. We expect tofund these expenditures from a balanced combination of additional issuances ofpartnership capital and long-term debt. Our planned internal growth projectswill require us to bear the cost of constructing these new assets before wewill begin to realize a return on them. While these major projects are underconstruction, our ability to increase distributions is likely to be limited.

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***Capital Resources***

*Available Credit*

A significant source of our liquidity is provided bythe commercial paper market. We have a $600 million commercial paper programsupported by our long-term Credit Facility which we access primarily to providetemporary financing for our operating activities, capital expenditures andacquisitions, at rates that are generally lower than the rates available underour Credit Facility. Under the terms of our commercial paper program, we mayissue up to $600 million of commercial paper. However, the amount of commercialpaper we may issue is reduced by any balance of outstanding letters of creditin excess of $400 million. At June 30, 2006, we had $600 million inprincipal amount of commercial paper outstanding and are currently at thecapacity available to us under our commercial paper program. We expect toextend the capacity of our commercial paper program to approximately $1billion, which extension will be subject to receipt of satisfactory creditratings from the major credit rating agencies.

Our Credit Facility alsoprovides us with another significant source of liquidity. In March 2006,we obtained an increase from $800 million to $1 billion in the aggregatecommitment available to us under the terms of our Credit Facility. The amountswe may borrow under the terms of our Credit Facility are reduced by theprincipal amount of our commercial paper issuances and the balance of ourletters of credit outstanding. At June 30, 2006 we had $10 millionoutstanding under our Credit Facility and letters of credit totaling$104.8 million. At June 30, 2006, we could borrow $285.2 millionunder the terms of our Credit Facility after reducing the $1 billion commitmentamount by the principal balance of commercial paper we have outstanding. Weexpect to extend the capacity of our Credit Facility to approximately $1.5billion in the near term, subject to approval of the lenders that are party toour Credit Facility.

***Cash Requirements for Future Growth***

*Capital Spending*

We rely upon cash flow from our operating activitiesand access to the capital markets to provide the funds necessary to execute ourgrowth strategy and complete our projects. Our success with generating andraising capital is a critical factor that determines how much we spend inconnection with our growth objectives. We believe our ability to generate orotherwise access the necessary capital resources is sufficient to meet thedemands of our current and future operating growth needs. Although we currentlyintend to make the forecasted expenditures discussed below, we may adjust thetiming and amounts of projected expenditures as necessary to adapt to changesin economic conditions.

We estimate our capital expenditures based on our longrange strategic operating and growth plans. These estimates may change due tofactors beyond our control, including changes in supplier prices, resourceconstraints and poor economic conditions. Additionally, estimates may change asa result of decisions made at a later date, which may include acquisitions,scope changes or operational considerations.

We categorize our capital expenditures as either coremaintenance or enhancement expenditures. Core maintenance expenditures arethose expenditures that are necessary to maintain the service capability of ourexisting assets and include the replacement of system components and equipmentwhich is worn, obsolete or completing its useful life. Enhancement expendituresimprove the service capability of our existing assets, extend asset usefullives, increase capacities from existing levels, reduce costs or enhancerevenues, and enable us to respond to governmental regulations and developingindustry standards. We made capital expenditures of approximately$285.2 million, including $24 million on core maintenance activities,during the six months ended June 30, 2006.

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Forthe full year of 2006, we anticipate our capital expenditures to approximatethe following (in millions):

| System enhancements          |   | $   | 390    |   |
|------------------------------|--------|-----|--------|--------|
| Core maintenance  activities |   | 55  |   |
| Southern Access expansion    |   | 155 |   |
| East Texas  expansion        |   | 340 |   |
|                              |   | $   | 940    |   |

 

We continue to expect our ongoing capital expendituresto be significant over the next three years due to the East Texas expansion andSouthern Access expansion projects. Our outlays for capital expenditures mayincrease as a result of the number of pipeline expansion projects beingconducted in the United States and the resulting demand these projects createfor skilled labor and supply resources. Our ability to attract the resourcesnecessary to complete our expansion projects may be negatively affected by theheavy demand for these resources.

We anticipate funding our system enhancement capitalexpenditures temporarily through the issuance of commercial paper and borrowingunder the terms of our Credit Facility, with permanent debt and equity fundingbeing obtained when appropriate. Core maintenance expenditures are expected tobe funded by operating cash flows.

Our Southern Access and East Texas expansion projectshave strong support from our customers, and upon completion each project isexpected to have stable cash flows. Although, we have received indications thatthese projects can be readily financed, we intend to structure the capacity ofour Credit Facility to support temporary expansion of our commercial paper programwhich will be refinanced with permanent capital at key milestone dates for eachproject.

As of June 30, 2006, we have contractualcommitments totaling $413.9 million for materials and services related to ourorganic growth projects. We anticipate settling these commitments during theremainder of 2006; however, we expect to make additional commitments as ourcapital projects continue to progress.

We also expect to incurcontinuing annual capital and operating expenditures for pipeline integritymeasures to ensure both regulatory compliance and to maintain the overallintegrity of our pipeline systems. Expenditure levels have continued toincrease as pipelines age and require higher levels of inspection ormaintenance; however, these are consistent with industry trends.

*Acquisitions*

We continue to assess various acquisition andexpansion opportunities to grow our business. However, the market for acquiringenergy transportation assets remains competitive. While we remain committed tomaking accretive acquisitions in or near areas where we already operate or havea competitive advantage, we will focus our efforts on development of ourexisting pipeline systems. Additionally, we may pursue opportunities to divestany non-strategic assets as conditions warrant.

We expect that the fundsneeded to achieve growth through acquisitions will be obtained throughissuances of commercial paper, term debt and additional partnership interests.

***Derivative Activities***

We use derivative financial instruments (i.e., futures,forwards, swaps, options and other financial instruments with similarcharacteristics) to mitigate the volatility of our cash flows and manage therisks associated with market fluctuations in commodity prices. Based on ourrisk management policies, all of our 

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derivative financialinstruments are employed in connection with an underlying asset, liability oranticipated transaction and are not entered into with the objective ofspeculating on commodity prices.

Thefollowing table provides summarized information about the timing and expectedsettlement amounts of our outstanding commodity derivative financialinstruments at June 30, 2006 for each of the indicated calendar years: 

|                        | ** ** | **Notional**                  | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **2012** | ** ** |
|------------------------|------------|-------------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|
| ** **             | ** ** | **($ in millions)** | ** ** |
| **Swaps**              |       |                          |       |     |       |     |       |     |       |     |       |     |       |     |       |     |       |
| Natural gas(1)         |       | 384,363,463                   |       | $        | (26.5      | )        | $          | (51.6    | )          | $        | (43.0      | )        | $          | (33.5    | )          | $        | (26.8      | ) | $ | (21.8 | ) | $ | (5.4 | ) |
| NGL(2)                 |       | 9,331,076                     |       | (30.2    | )          | (40.6    | )          | (12.6    | )          | (5.6     | )          | (1.9     | )          | —   |       | —   |       |
| Crude(2)               |       | 1,162,074                     |       | (6.3     | )          | (12.4    | )          | (8.6     | )          | (2.4     | )          | (0.8     | )          | —   |       | —   |       |
| **Options—calls** |       |                          |       |     |       |     |       |     |       |     |       |     |       |     |       |     |       |
| Natural gas(1)         |       | 2,010,000                     |       | (0.5     | )          | (1.7     | )          | (1.5     | )          | (1.3     | )          | (1.2     | )          | (1.0     | )          | —   |       |
| **Options—puts**  |       |                          |       |     |       |     |       |     |       |     |       |     |       |     |       |     |       |
| Natural gas(1)         |       | 2,010,000                     |       | —   |       | —   |       | —   |       | —   |       | —   |       | 0.1      |       | —   |       |
| Totals                 |       |                          |       | $        | (63.5      | )        | $          | (106.3   | )          | $        | (65.7      | )        | $          | (42.8    | )          | $        | (30.7      | ) | $ | (22.7 | ) | $ | (5.4 | ) |

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(1)        Notionalamounts for natural gas are recorded in MMBtu.

(2)                Notionalamounts for NGL and Crude are recorded in Bbl.

***Operating Activities***

Net cash provided by ouroperating activities for the six months ended June 30, 2006 was$167.0 million, an increase of $43.3 million over the $123.7 millionwe generated for the same period in 2005. The improved operating cash flow isprimarily attributable to income contributions from our natural gas processingassets and increased deliveries on our Lakehead system, as well as the generaltiming differences in the collection on and payment of our current and relatedparty accounts.

***Investing Activities***

We used $44.1 million lessin our investing activities during the six months ended June 30, 2006compared with the same period in 2005. This decrease is primarily attributablea decrease in expenditures made during the first six months of 2006 foracquisitions than we made during the first six months of 2005 as a result ofour shift in strategy to more internal growth projects. The decrease inexpenditures for acquisitions was partially offset by the approximate $110.5million increase in our investments in property, plant and equipment during thefirst six months of 2006 over the amount spent during the same period of 2005.The increase in our capital expenditures in the second quarter of 2006 isdirectly attributable to our previously announced expansion projects.

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***Financing Activities***

Net cash provided by ourfinancing activities during the six months ended June 30, 2006 was$145.9 million, compared with $238.0 million for the correspondingperiod in 2005. During the first six months of 2006 we did not issue any additionalunits, whereas in the first six months of 2005 we raised $127.5 million fromunit issuances. During the first six months of 2006 we had net commercial paperissuances of $269.1 million, which include gross issuances of $1,648.9 millionand gross repayments of $1,379.8 million. We also borrowed $10 million duringthe first six months of 2006 under the terms of our Credit Facility and repaid$20 million in principal amount of an affiliate loan. During the first sixmonths of 2005, we repaid $175 million, net of borrowings, under the terms ofour Credit Facility, including borrowingsand repayments of $565 million representing net non-cash settlements with theparties to our Credit Facility. Distributions to our partners werehigher in the first six months of 2006 due to an increase in the weightedaverage number of units outstanding in relation to the six months of 2005 andthe related increase in the general partner incentive distributions resultingfrom the larger number of units outstanding.

**OFF-BALANCESHEET ARRANGEMENTS**

We do not have any off-balancesheet arrangements.

**SUBSEQUENT EVENTS**

***Distribution to Partners***

On July 28, 2006, theBoard of Directors of Enbridge Management declared a distribution payable toour partners on August 14, 2006. The distribution will be paid tounitholders of record as of August 4, 2006, of our available cash of$68.1 million at June 30, 2006, or $0.925 per common unit. Of thisdistribution, $56.6 million will be paid in cash, $11.3 million willbe distributed in i-units to our i-unitholder and $0.2 millionwill be retained from the General Partner in respect of this i-unitdistribution.

**REGULATORY MATTERS**

***FERC Transportation Tariffs-***Liquids

Beginning July 1, 2005, we increased our ratesfor transportation on our Lakehead, North Dakota and Ozark systems incompliance with the indexed rate ceilings allowed by the Federal EnergyRegulatory Commision, or FERC. In March 2006, the FERC established a newoil pipeline pricing index for a five-year period ending July 2011. Theindex is used to establish rate ceiling levels for oil pipeline rate changes. TheFERC determined that the Producer Price Index for Finished Goods plus 1.3percent (PPI+1.3 percent) should be the oil pricing index for the five yearperiod beginning July 1, 2006. For our Lakehead system indexing onlyapplies to our base rates and not the SEP II, Terrace and Facilities surcharges.On our Lakehead system, we increased our rates by an average of 3.0 percent,which is less than the amount allowed under the index. On our Lakehead system,the new rate for heavy crude movements from the International Boarder nearNeche, North Dakota to Chicago, Illinois is $0.919 per barrel, which reflectsan approximate $0.021 per barrel increase over rates filed effective April 1,2006. In addition to the rates on our Lakehead system, we increased thetransportation rates by an average of approximately 6.1 percent on our NorthDakota and Ozark systems. 

Effective April 1,2006, we filed our annual tariff with the FERC for our Lakehead System SEP IIexpansion. This tariff reflected the annual calculation of the SEP II andother surcharges based on true-ups of prior year amounts and estimates for2006, and an adjustment for the Terrace surcharge as a result of lower thanexpected volumes moving on the Lakehead system in 2005. This filing increasedthe tariff for 

33

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heavycrude oil movements from the Canadian border to Chicago, Illinois, byapproximately $0.008 per barrel, to approximately $0.898 per barrel.

**Item3.**                        Quantitativeand Qualitative Disclosures About Market Risk

This information updates, and you should read it inconjunction with, our quantitative and qualitative disclosures about marketrisks reported in our Annual Report on Form 10-K for the year ended December 31,2005, in addition to information presented in Items 1 and 2 of this QuarterlyReport on Form 10-Q.

Our net income and cashflows are subject to volatility stemming from changes in commodity prices ofnatural gas, NGLs, condensate and fractionation margins (the relative pricedifferential between NGL sales and offsetting natural gas purchases). Thismarket price exposure exists within our Natural Gas and Marketing segments. Tomitigate the volatility of our cash flows, we use derivative financialinstruments (i.e., futures, forwards, swaps, options and other financialinstruments with similar characteristics) to manage the risks associated withmarket fluctuations in commodity prices. Based on our risk management policies,all of our derivative financial instruments are employed in connection with anunderlying asset, liability and/or forecasted transaction and are not enteredinto with the objective of speculating on commodity prices.

Thefollowing tables provide information about our derivative financial instrumentsat June 30, 2006 and December 31, 2005, with respect to our commodityprice risk management activities for natural gas and NGLs, including crude oil:

|                                  | ** **   | **At June 30, 2006** | ** **   | **At December 31, 2005** | ** **   |
|----------------------------------|--------------|-------------------------------------|--------------|-----------------------------------------|--------------|
| ** **                       | ** **   | ** **                          | ** **   | ** **                              | ** **   | **Wtd Avg Price**(2) | ** ** | **Fair Value**(3) | ** ** | **Fair Value**(3) | ** ** |
| ** **                       | ** **   | **Commodity**                       | ** **   | **Notional**(1)                         | ** **   | **Receive** | ** ** | **Pay** | ** ** | **Asset** | ** ** | **Liability** | ** ** | **  Asset  ** | ** ** | **  Liability  ** | ** ** |
| ***Contracts maturing in 2006*** | *** *** | *** ***                        | *** *** | *** ***                            | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** |   | *** *** | *** *** |   | *** *** | *** *** |   | *** *** | *** *** |   |
| *Swaps*                          | * *     | * *                            | * *     | * *                                | * *     | * * | * * | * * | * * | * * | * * |   | * * | * * |   | * * | * * |   | * * | * * |   |
| Receive variable/pay fixed       |         | Natural  gas                        |         | 72,335,726                              |         | $ | 6.22 |   | $ | 7.10 |   | $ | 11.5 |   |   | $ | (74.6 | ) |   | $ | 380.6 |   |   | $ | (11.7 | ) |   |
| Receive fixed/pay variable       |         | Natural  gas                        |         | 74,238,411                              |         | 7.04 |   | 6.53 |   | 69.1 |   |   | (31.3 | ) |   | 14.5 |   |   | (467.8 | ) |   |
|                                  |         | NGL                                 |         | 2,570,388                               |         | 36.47 |   | 48.44 |   | 0.2 |   |   | (30.4 | ) |   | — |   |   | (29.7 | ) |   |
|                             |         | Crude  oil                          |         | 203,320                                 |         | 44.18 |   | 75.54 |   | — |   |   | (6.3 | ) |   | 0.2 |   |   | (7.8 | ) |   |
| Receive variable/pay  variable   |         | Natural  gas                        |         | 24,685,773                              |         | 5.74 |   | 5.79 |   | 1.7 |   |   | (2.9 | ) |   | 5.2 |   |   | (5.2 | ) |   |
| *Options*                        | * *     | * *                            | * *     | * *                                | * *     | * * | * * | * * | * * | * * | * * |   | * * | * * |   | * * | * * |   | * * | * * |   |
| Calls (written)                  |         | Natural  gas                        |         | 184,000                                 |         | 7.17 |   | 4.31 |   | — |   |   | (0.5 | ) |   | — |   |   | (2.0 | ) |   |
| Puts                             |         | Natural gas                         |         | 184,000                                 |         | 7.17 |   | 3.40 |   | — |   |   | — |   |   | — |   |   | — |   |   |
| ***Contracts maturing in 2007*** |         |                                |         |                                    |         |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                          |         |                                |         |                                    |         |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive variable/pay fixed       |         | Natural gas                         |         | 58,447,507                              |         | 8.48 |   | 7.55 |   | 64.1 |   |   | (12.5 | ) |   | 112.0 |   |   | (1.0 | ) |   |
| Receive fixed/pay variable       |         | Natural gas                         |         | 63,874,041                              |         | 7.29 |   | 9.00 |   | 10.5 |   |   | (114.2 | ) |   | 0.5 |   |   | (170.0 | ) |   |
|                                  |         | NGL                                 |         | 3,428,810                               |         | 33.38 |   | 45.93 |   | 0.6 |   |   | (41.2 | ) |   | — |   |   | (22.5 | ) |   |
|                             |         | Crude oil                           |         | 388,680                                 |         | 42.05 |   | 76.00 |   | — |   |   | (12.4 | ) |   | — |   |   | (7.9 | ) |   |
| Receive variable/pay  variable   |         | Natural gas                         |         | 7,594,666                               |         | 8.92 |   | 8.85 |   | 1.1 |   |   | (0.6 | ) |   | 0.7 |   |   | (0.1 | ) |   |
| *Options*                        |         | * *                            |         | * *                                |         | * * |   | * * |   | * * |   |   | * * | * * |   | * * |   |   | * * | * * |   |
| Calls (written)                  |         | Natural gas                         |         | 365,000                                 |         | 9.18 |   | 4.31 |   | — |   |   | (1.7 | ) |   | — |   |   | (2.0 | ) |   |
| Puts                             |         | Natural gas                         |         | 365,000                                 |         | 9.18 |   | 3.40 |   | — |   |   | — |   |   | — |   |   | — |   |   |
|                                  |              |                                     |              |                                         |              |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

34

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|                                      | ** **   | **At June 30, 2006** | ** **   | **At December 31, 2005** | ** **   |
|--------------------------------------|--------------|-------------------------------------|--------------|-----------------------------------------|--------------|
| ** **                           | ** **   | ** **                          | ** **   | ** **                              | ** **   | **Wtd Avg Price**(2) | ** ** | **Fair Value**(3) | ** ** | **Fair Value**(3) | ** ** |
| ** **                           | ** **   | **Commodity**                       | ** **   | **Notional**(1)                         | ** **   | **Receive** | ** ** | **Pay** | ** ** | **Asset** | ** ** | **Liability** | ** ** | **   Asset   ** | ** ** | **   Liability   ** | ** ** |
| ***Contracts maturing in  2008***    | *** *** | *** ***                        | *** *** | *** ***                            | *** *** |   | *** *** | *** *** |   | *** *** | *** *** | *** *** | *** *** |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |
| *Swaps*                              | * *     | * *                            | * *     | * *                                | * *     |   | * * | *** *** |   | * * | * * | * * | * * |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Receive variable/pay fixed           |         | Natural gas                         |         | 14,805,941                              |         |   | 8.60 | *** *** |   | 7.30 |   | 20.0 |   |   | (2.4 | ) |   |   | 18.5 | *** *** |   |   | — |   |   |
| Receive fixed/pay  variable          |         | Natural gas                         |         | 22,654,508                              |         |   | 6.09 | *** *** |   | 9.08 |   | 0.8 |   |   | (62.0 | ) |   |   | — | *** *** |   |   | (66.3 | ) |   |
|                                      |         | NGL                                 |         | 1,607,253                               |         |   | 37.25 | *** *** |   | 46.02 |   | — |   |   | (12.6 | ) |   |   | — | *** *** |   |   | (7.2 | ) |   |
|                                 |         | Crude oil                           |         | 323,699                                 |         |   | 44.18 | *** *** |   | 73.81 |   | — |   |   | (8.6 | ) |   |   | — | *** *** |   |   | (5.2 | ) |   |
| Receive variable/pay variable        |         | Natural gas                         |         | 4,204,000                               |         |   | 8.94 | *** *** |   | 8.78 |   | 0.7 |   |   | (0.1 | ) |   |   | 1.0 | *** *** |   |   | — |   |   |
| *Options*                            | * *     | * *                            | * *     | * *                                | * *     |   | * * | *** *** |   | * * | * * | * * | * * |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Calls (written)                      |         | Natural gas                         |         | 366,000                                 |         |   | 8.92 | *** *** |   | 4.31 |   | — |   |   | (1.5 | ) |   |   | — | *** *** |   |   | (1.7 | ) |   |
| Puts                                 |         | Natural gas                         |         | 366,000                                 |         |   | 8.92 | *** *** |   | 3.40 |   | — |   |   | — |   |   |   | — | *** *** |   |   | — |   |   |
| ***Contracts maturing in  2009***    | *** *** | *** ***                        | *** *** | *** ***                            | *** *** |   | *** *** | *** *** |   | *** *** | *** *** | *** *** | *** *** |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |
| *Swaps*                              | * *     | * *                            | * *     | * *                                | * *     |   | * * | *** *** |   | * * | * * | * * | * * |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Receive variable/pay fixed           |         | Natural gas                         |         | 4,557,390                               |         |   | 7.98 | *** *** |   | 7.21 |   | 4.7 |   |   | (1.8 | ) |   |   | — | *** *** |   |   | — |   |   |
| Receive fixed/pay  variable          |         | Natural gas                         |         | 12,227,500                              |         |   | 4.93 | *** *** |   | 8.45 |   | 0.1 |   |   | (36.6 | ) |   |   | — | *** *** |   |   | (34.5 | ) |   |
|                                      |         | NGL                                 |         | 1,407,075                               |         |   | 41.05 | *** *** |   | 45.75 |   | — |   |   | (5.6 | ) |   |   | — | *** *** |   |   | (0.6 | ) |   |
|                                 |         | Crude oil                           |         | 155,125                                 |         |   | 53.13 | *** *** |   | 71.81 |   | — |   |   | (2.4 | ) |   |   | — | *** *** |   |   | (1.0 | ) |   |
| Receive variable/pay variable        |         | Natural gas                         |         | 4,197,500                               |         |   | 8.03 | *** *** |   | 8.00 |   | 0.1 |   |   | — |   |   |   | 1.1 | *** *** |   |   | — |   |   |
| *Options*                            | * *     | * *                            | * *     | * *                                | * *     |   | * * | *** *** |   | * * | * * | * * | * * |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Calls (written)                      |         | Natural gas                         |         | 365,000                                 |         |   | 8.45 | *** *** |   | 4.31 |   | — |   |   | (1.3 | ) |   |   | — | *** *** |   |   | (1.4 | ) |   |
| Puts                                 |         | Natural gas                         |         | 365,000                                 |         |   | 8.45 | *** *** |   | 3.40 |   | — |   |   | — |   |   |   | — | *** *** |   |   | — |   |   |
| ***Contracts maturing in  2010***    | *** *** | *** ***                        | *** *** | *** ***                            | *** *** |   | *** *** | *** *** |   | *** *** | *** *** | *** *** | *** *** |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |
| *Swaps*                              | * *     | * *                            | * *     | * *                                | * *     |   | * * | *** *** |   | * * | * * | * * | * * |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Receive variable/pay fixed           |         | Natural gas                         |         | 730,000                                 |         |   | 8.04 | *** *** |   | 3.57 |   | 2.6 |   |   | — |   |   |   | — | *** *** |   |   | — |   |   |
| Receive fixed/pay  variable          |         | Natural gas                         |         | 9,490,000                               |         |   | 4.11 | *** *** |   | 7.97 |   | 0.1 |   |   | (29.5 | ) |   |   | 0.1 | *** *** |   |   | (25.9 | ) |   |
|                                      |         | NGL                                 |         | 317,550                                 |         |   | 30.60 | *** *** |   | 38.19 |   | — |   |   | (1.9 | ) |   |   | — | *** *** |   |   | (0.4 | ) |   |
|                                 |         | Crude oil                           |         | 91,250                                  |         |   | 59.00 | *** *** |   | 70.23 |   | — |   |   | (0.8 | ) |   |   | — | *** *** |   |   | (0.1 | ) |   |
| *Options*                            | * *     | * *                            | * *     | * *                                | * *     |   | * * | *** *** |   | * * | * * | * * | * * |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Calls (written)                      |         | Natural gas                         |         | 365,000                                 |         |   | 8.04 | *** *** |   | 4.31 |   | — |   |   | (1.2 | ) |   |   | — | *** *** |   |   | (1.1 | ) |   |
| Puts                                 |         | Natural gas                         |         | 365,000                                 |         |   | 8.04 | *** *** |   | 3.40 |   | — |   |   | — |   |   |   | — | *** *** |   |   | — |   |   |
| ***Contracts  maturing after 2010*** |         |                                |         |                                    |         |   |   | *** *** |   |   |   |   |   |   |   |   |   |   |   | *** *** |   |   |   |   |   |
| *Swaps*                              |         |                                |         |                                    |         |   |   | *** *** |   |   |   |   |   |   |   |   |   |   |   | *** *** |   |   |   |   |   |
| Receive  variable/pay fixed          |         | Natural gas                         |         | 912,000                                 |         |   | 7.98 | *** *** |   | 3.57 |   | 3.0 |   |   | — |   |   |   | — | *** *** |   |   | — |   |   |
| Receive fixed/pay variable           |         | Natural gas                         |         | 9,408,500                               |         |   | 3.62 | *** *** |   | 7.89 |   | — |   |   | (30.2 | ) |   |   | — | *** *** |   |   | (26.1 | ) |   |
| *Options*                            |         |                                |         |                                    |         |   |   | *** *** |   |   |   |   |   |   |   |   |   |   |   | *** *** |   |   |   |   |   |
| Calls (written)                      |         | Natural gas                         |         | 365,000                                 |         |   | 7.62 | *** *** |   | 4.31 |   | — |   |   | (1.0 | ) |   |   | — | *** *** |   |   | (0.9 | ) |   |
| Puts                                 |         | Natural gas                         |         | 365,000                                 |         |   | 7.62 | *** *** |   | 3.40 |   | 0.1 |   |   | — |   |   |   | — | *** *** |   |   | — |   |   |
|                                 |         |                                |         |                                    |         |   |   | *** *** |   |   |   |   |   |   |   |   |   |   |   | *** *** |   |   |   |   |   |

 

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(1)      Volumes of Natural gas are measured in MMBtu,whereas volumes of NGL and Crude are measured in Barrels, or Bbl.

35

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(2)              Weighted average prices received and paid arein $/MMBtu for Natural gas and in $/Bbl for NGL and Crude.

(3)              The fair value is determined based on quoted marketprices at June 30, 2006 and December 31, 2005, respectively,discounted using the swap rate for the respective periods to consider the timevalue of money. Fair values are presented in millions of dollars.

***Accounting Treatment***

All derivative financial instruments are recorded inthe consolidated financial statements at fair market value and are adjustedeach period for changes in the fair market value (“mark-to-market”).The fair market value of these derivative financial instruments reflects theestimated amounts that we would pay or receive, other than in a forced orliquidation sale, to terminate or close the contracts at the reporting date,taking into account the current unrealized losses or gains on open contracts.We use actively traded external market quotes and indices to valuesubstantially all of the financial instruments we utilize.

Under the guidance of Statement of FinancialAccounting Standards No. 133, *Accountingfor Derivative Transactions and Hedging Activities* (“SFAS No. 133”),if a derivative financial instrument does not qualify as a hedge or is notdesignated as a hedge, a change in the fair market value, both realized andunrealized, is recognized currently in our income statement as a derivativefair value gain (loss) and recorded in Cost of natural gas. Cash flow is onlyimpacted to the extent the actual derivative contract is settled by making orreceiving a payment to or from the counterparty or by making or receiving apayment for entering into a contract that exactly offsets the originalderivative contract. Typically, we settle our derivative contracts when thephysical transaction that underlies the derivative financial instrument occurs.

If a derivative financialinstrument qualifies and is designated as a cash flow hedge, a hedge of aforecasted transaction or future cash flows, any unrealized mark-to-market gainor loss is deferred in Accumulated other comprehensive income (“OCI”), acomponent of Partners’ Capital, until the underlying hedged transaction occurs.To the extent that the hedge instrument is effective in offsetting thetransaction being hedged, there is no impact to the income statement. Atinception and on a quarterly basis, we formally assess whether the hedgecontract is highly effective in offsetting changes in cash flows of hedgeditems. Any ineffective portion of a cash flow hedge’s change in fair marketvalue is recognized each period in earnings. Realized gains and losses onderivative financial instruments that are designated as hedges and qualify forhedge accounting are included in Cost of natural gas in the period the hedgedtransaction occurs. Gains and losses deferred in OCI related to cash flowhedges for which hedge accounting has been discontinued, remain in OCI untilthe underlying physical transaction occurs unless it is probable that theforecasted transaction will not occur by the end of the originally specifiedtime period or within an additional two-month period of time thereafter.Generally, our preference is for our derivative financial instruments toreceive hedge accounting treatment whenever possible, to mitigate the non-cashearnings volatility that arises under mark-to-market accountingtreatment. To qualify for cash flow hedge accounting, very specificrequirements must be met in terms of hedge structure, hedge objective and hedgedocumentation.

***Non-Qualified Hedges***

Many of our derivative financial instruments qualifyfor hedge accounting treatment under the specific requirements of SFAS No. 133.However, we have four primary transaction types where the hedge structure doesnot meet the requirements to apply hedge accounting and, therefore, thesefinancial instruments are considered ‘non-qualified’ under SFAS No. 133.These non-qualified derivative financial instruments must be adjusted to theirfair market value, or marked-to-market, each period, with theincreases and decreases in fair value recorded as increases and decreases inCost of natural gas in our 

36

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Consolidated Statements ofIncome. These mark-to-market adjustments produce a degree ofearnings volatility that can often be significant from period to period, buthave no cash flow impact relative to changes in market prices. The cash flowimpact occurs when the underlying physical transaction takes place in thefuture and an associated financial instrument contract settlement is made.

The four instances of non-qualified hedges are asfollows:

1.                **Transportation—**In our Marketing segment, when the pricingindex used for gas sales is different from the pricing index used for gaspurchases, we are exposed to relative changes in those two indices. By enteringinto a basis swap between those two indices, we can effectively lock in themargin on the combined gas purchase and gas sale, removing any market pricerisk on the physical transactions. Although this represents a sound economichedging strategy, these types of derivative transactions do not qualify forhedge accounting under SFAS No. 133, as the ultimate cash flow has notbeen fixed, only the margin.

2.                **Storage—**In our Marketing segment, when we use derivativefinancial instruments to hedge market spreads around our owned or contractedassets, such as our gas storage portfolio, the underlying forecastedtransaction may or may not occur in the same period as originally forecast.This can occur because we have the flexibility to make changes in theunderlying injection or withdrawal schedule, given changes in marketconditions. Therefore, these transactions do not qualify for cash flow hedgeaccounting treatment under SFAS No. 133, since the occurrence of thetransactions cannot be accurately forecast. Although these derivative financialinstruments are associated with the underlying natural gas storage portfolio,the derivative financial instruments are often settled in periods that are differentthan the periods when the physical natural gas is purchased for storage or soldfrom storage. Because the physical natural gas is recorded at the lower of costor market, timing differences can result when the derivative financialinstrument is settled in a period that is different from when the physicalnatural gas is sold. As a result, derivative financial instruments associatedwith our natural gas storage activities can create volatility in our earnings.

3.                **Natural Gas Collars—**In our Natural Gas segment, we hadpreviously entered into natural gas collars to hedge the sales price of naturalgas. The natural gas collars were based on a NYMEX price, while the physicalgas sales were based on a different index. To better align the index of thenatural gas collars with the index of the underlying sales, we de-designatedthe original cash flow hedging relationship with the intent ofcontemporaneously re-designating the natural gas collars as hedges offorecasted physical natural gas sales with a NYMEX pricing index to bettermatch the indices, which was a sound economic hedging strategy. However,because the fair value of these derivative instruments was a liability to us atre-designation, they are considered net written options under SFAS No. 133and do not qualify for hedge accounting. These derivatives are being marked-to-market,with the changes in fair value from the date of de-designation recordedto earnings each period. As a result, our operating income will be subject togreater volatility due to movements in the prices of natural gas until theunderlying long-term transactions are settled.

4.                **Optional Natural Gas Processing Volumes**—In our Natural Gassegment we use derivative financial instruments to hedge the prices of NGLsassociated with some of the volumes produced from our natural gas processingactivities. Our natural gas contracts allow us the option of processing naturalgas when it is economical, and ceasing to do so when processing becomesuneconomic. We have entered into derivative financial instruments to fix thesales price of a portion of the NGLs that we produce at our discretion and tofix the related purchases of natural gas required for processing. Some of thesederivatives do not qualify for hedge accounting under SFAS No. 133 becausewe are unable to forecast the NGLs to be processed that underlie the derivativesince we have the option of processing or not processing as conditions warrant.As a 

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result, our operatingincome will be subject to increased volatility due to movements in the pricesof NGLs until the underlying long-term transactions are settled.

In each of the instances described above, theunderlying physical purchase, storage and sale of natural gas and NGLs areaccounted for on a historical cost basis rather than on the mark-to-marketbasis we utilize for the financial derivatives used to mitigate (hedge) thecommodity price risk associated with our storage and transportation assets.This difference in accounting (i.e.,the financial derivative is recorded at fair market values while the physicaltransaction is recorded at historical cost) can and has resulted involatility in our reported net income, even though the economic margin isessentially unchanged from the date the transactions were consummated.

Thefollowing table presents the unrealized gains and losses associated withchanges in the fair value of our commodity price derivatives, which arerecorded as an element of Cost of natural gas in our Consolidated Statements ofIncome and disclosed as a reconciling item on our Statements of Cash Flows:

|                                       | ** ** | **Three months ended  June 30,** | ** ** | **Six months ended  June 30,** | ** ** |
|---------------------------------------|------------|-------------------------------------------------|------------|-----------------------------------------------|------------|
| ** **                            | ** ** | **   2006   **    | ** ** | **   2005   **  | ** ** | **   2006   ** | ** ** | **   2005   ** | ** ** |
| ** **                            | ** ** | **(in millions)**                          | ** ** |
| Natural Gas segment                   |       |                                            |       |                                          |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Ineffectiveness                       |       |                                            | $          | (0.1                                          | )          |   |   | $ | (1.8 | ) |   |   | $ | (0.1 | ) |   |   | $ | (2.0 | ) |   |
| Non-qualified hedges                  |       |                                            | (3.6       | )                                             |       |   | (2.9 | ) |   |   | (1.8 | ) |   |   | (11.1 | ) |   |
| Marketing                             |       |                                            |       |                                          |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Non-qualified hedges                  |       |                                            | 5.4        |                                          |       |   | 3.9 |   |   |   | 31.3 |   |   |   | 5.3 |   |   |
| Discontinuance                        |       |                                            | —     |                                          |       |   | (9.0 | ) |   |   | — |   |   |   | (9.0 | ) |   |
| Derivative fair value gains  (losses) |       |                                            | $          | 1.7                                           |       |   |   | $ | (9.8 | ) |   |   | $ | 29.4 |   |   |   | $ | (16.8 | ) |   |

 

We record the change in fair value of our highlyeffective cash flow hedges in OCI until the derivative financial instrumentsare settled, at which time they are reclassified to earnings. Also included inOCI are unrecognized losses of approximately $6.3 million associated withderivative financial instruments that qualified for and were classified as cashflow hedges of forecasted transactions that were subsequently de-designated.These unrecognized losses are reclassified to earnings over the periods duringwhich the originally hedged forecasted transactions affect earnings. For thethree and six months ended June 30, 2006, we reclassified unrealizedlosses of $14.9 million and $39.7 million from OCI to Cost of natural gas onour Consolidated Statements of Income for the fair value of derivativefinancial instruments that were settled.

Ourderivative financial instruments are included at their fair values in theConsolidated Statements of Financial Position as follows:

|                              | ** ** | **June 30,  2006** | ** ** | **December 31,  2005** | ** ** |
|------------------------------|------------|-------------------------|------------|-----------------------------|------------|
| ** **                   | ** ** | **(in millions)**  | ** ** |
| Other current assets         |       | $                       | 4.6        |                        |       | $ | 5.8 |   |   |
| Other assets, net            |       | 8.5                     |       |                        | 4.2        |   |   |
| Accounts payable and other   |       | (123.0                  | )          |                        | (129.2     | ) |   |
| Other long-term  liabilities |       | (219.9                  | )          |                        | (243.0     | ) |   |
|                              |       | $                       | (329.8     | )                           |       | $ | (362.2 | ) |   |

 

The decrease in our obligation associated withderivative activities is primarily due to the decline in current and forwardnatural gas prices from December 31, 2005 to June 30, 2006. ThePartnership’s portfolio of derivative financial instruments is largelycomprised of long-term fixed price sales and purchase agreements.

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We do not requirecollateral or other security from the counterparties to our derivativefinancial instruments, all of which were rated “BBB+” or better by the majorcredit rating agencies.

**Item 4.**                        Controlsand Procedures

The Partnership and Enbridge maintain systems of disclosurecontrols and procedures designed to provide reasonable assurance that we areable to record, process, summarize and report the information required in ourannual and quarterly reports under the Securities Exchange Act of 1934. Ourmanagement has evaluated the effectiveness of our disclosure controls andprocedures as of June 30, 2006. Based upon that evaluation, our principalexecutive officer and principal financial officer concluded that our disclosurecontrols and procedures are effective to accomplish their purpose. Inconducting this assessment, our management relied on similar evaluationsconducted by employees of Enbridge affiliates who provide certain treasury,accounting and other services on our behalf. No changes in our internal controlover financial reporting were made during the three months ended June 30,2006, that would materially affect our internal control over financialreporting, nor were any corrective actions with respect to significantdeficiencies or material weaknesses necessary subsequent to that date.

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**PART II—OTHERINFORMATION**

**Item 1.**                        LegalProceedings

Refer to Part I,Item 1. Financial statements, Note 9, which is incorporated herein byreference.

**Item 1A.**                RiskFactors

The risk factors presented below update and should beconsidered in addition to the risk factors previously disclosed in our AnnualReport on Form 10-K for the fiscal year ended December 31,2005.

***Our partnership agreement and thedelegation of control agreement limit the fiduciary duties that EnbridgeManagement and our general partner owe to our unitholders and restrict theremedies available to our unitholders for actions taken by Enbridge Managementand our general partner that might otherwise constitute a breach of a fiduciaryduty.***

Our partnershipagreement contains provisions that modify the fiduciary duties that our generalpartner would otherwise owe to our unitholders under state fiduciary duty law.Through the delegation of control agreement, these modified fiduciary dutiesalso apply to Enbridge Management as the delegate of our general partner. Forexample, our partnership agreement:

·       permitsour general partner to make a number of decisions, including the determinationof which factors it will consider in resolving conflicts of interest, in its “solediscretion.” This entitles our general partner to consider only the interestsand factors that it desires, and it has no duty or obligation to giveconsideration to any interest of, or factors affecting, us, our affiliates orany unitholder;

·       providesthat any standard of care and duty imposed on our general partner will bemodified, waived or limited as required to permit our general partner to actunder our partnership agreement and to make any decision pursuant to theauthority prescribed in our partnership agreement, so long as such action isreasonably believed by the general partner to be in our best interests; and

·       providesthat our general partner and its directors and officers will not be liable formonetary damages to us or our unitholders for any acts or omissions if theyacted in good faith.

These and similar provisions in our partnershipagreement may restrict the remedies available to our unitholders for actionstaken by Enbridge Management or our general partner that might otherwiseconstitute a breach of a fiduciary duty.

***Potential conflicts of interestmay arise among Enbridge and its shareholders, on the one hand, and us and ourunitholders and Enbridge Management and its shareholders, on the other hand.Because the fiduciary duties of the directors of our general partner andEnbridge Management have been modified, the directors may be permitted to makedecisions that benefit Enbridge and its shareholders or Enbridge Management andits shareholders more than us and our unitholders.***

Conflicts ofinterest may arise from time to time among Enbridge and its shareholders, onthe one hand, and us and our unitholders and Enbridge Management and itsshareholders, on the other hand. Conflicts of interest may also arise from timeto time between us and our unitholders, on the one hand, and EnbridgeManagement and its shareholders, on the other hand. In managing and controllingus as the delegate of our general partner, Enbridge Management may consider theinterests of all parties to a conflict and may resolve those conflicts by makingdecisions that benefit Enbridge and its shareholders or Enbridge Management andits shareholders more than us and our unitholders. The following decisions,among others, could involve conflicts of interest:

·       whetherwe or Enbridge Inc. will pursue certain acquisitions or other businessopportunities;

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·       whetherwe will issue additional units or other equity securities or whether we willpurchase outstanding units;

·       whetherEnbridge Management will issue additional shares;

·       theamount of payments to Enbridge and its affiliates for any services rendered forour benefit;

·       theamount of costs that are reimbursable to Enbridge Management or Enbridge andits affiliates by us;

·       theenforcement of obligations owed to us by Enbridge Management, our generalpartner or Enbridge, including obligations regarding competition betweenEnbridge and us; and

·       theretention of separate counsel, accountants or others to perform services for usand Enbridge Management.

In these and similar situations, any decision by EnbridgeManagement may benefit one group more than another, and in making suchdecisions, Enbridge Management may consider the interests of all groups, aswell as other factors, in deciding whether to take a particular course ofaction.

In other situations,Enbridge may take certain actions, including engaging in businesses thatcompete with us, that are adverse to us and our unitholders. For example,although Enbridge and its subsidiaries are generally restricted from engagingin any business that is in direct material competition with our businesses,that restriction is subject to the following significant exceptions:

·       Enbridgeand its subsidiaries are not restricted from continuing to engage inbusinesses, including the normal development of such businesses, in which theywere engaged at the time of our initial public offering in December 1991;

·       suchrestriction is limited geographically only to those routes and products forwhich we provided transportation at the time of our initial public offering;

·       Enbridgeand its subsidiaries are not prohibited from acquiring any business thatmaterially and directly competes with us as part of a larger acquisition, solong as the majority of the value of the business or assets acquired, inEnbridge’s reasonable judgment, is not attributable to the competitivebusiness; and

·       Enbridgeand its subsidiaries are not prohibited from acquiring any business thatmaterially and directly competes with us if that business is first offered foracquisition to us and the board of directors of Enbridge Management and ourunitholders determine not to pursue the acquisition.

Since we were not engaged in any aspect of the naturalgas business at the time of our initial public offering, Enbridge and itssubsidiaries are not restricted from competing with us in any aspect of thenatural gas business. In addition, Enbridge and its subsidiaries would bepermitted to transport crude oil and liquid petroleum over routes that are notthe same as our Lakehead system, even if such transportation is in directmaterial competition with our business.

These exceptions alsoexpressly permitted the reversal by Enbridge in 1999 of one of its pipelinesthat extends from Sarnia, Ontario to Montreal, Quebec. As a result of thisreversal, Enbridge competes with us to supply crude oil to the Ontario, Canadamarket.

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**Item 6.**                        Exhibits

Each exhibit identifiedbelow is filed as part of this document. Exhibits not incorporated by referenceto a prior filing are designated by an “*”; all exhibits not so designated areincorporated herein by reference to a previous filing as indicated.
| 3.1   |   | Certificate of Limited Partnership of the  Partnership (incorporated by reference to Exhibit 3.1 to the  Partnership’s Registration Statement No. 33-43425).                                                  |
|-------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.2   |   | Certificate of Amendment  to Certificate of Limited Partnership of the Partnership (incorporated by  reference to Exhibit 3.2 to the Partnership’s 2000 Form 10-K/A  dated October 9, 2001).             |
| 3.3   |   | Third Amended and  Restated Agreement of Limited Partnership of the Partnership (incorporated by  reference to Exhibit 3.1 to the Partnership’s Quarterly Report on  Form 10-Q filed November 14, 2002). |
| 4.1   |   | Form of Certificate  representing Class A Common Units (incorporated by reference to Exhibit 4.1  to the Partnership’s 2000 Form 10-K/A dated October 9, 2001).                                |
| 10.1  |   | Employment agreement  between Mr. Letwin and Enbridge Inc. dated April 14, 2003  (incorporated by reference to our Current Report on Form 8-K dated  May 3, 2006).                                       |
| 31.1* |   | Certification of  Principal Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley  Act of 2002.                                                                                                          |
| 31.2* |   | Certification of  Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley  Act of 2002.                                                                                                          |
| 32.1* |   | Certification of  Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley  Act of 2002.                                                                                                          |
| 32.2* |   | Certification of  Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley  Act of 2002.                                                                                                          |

 

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**SIGNATURES**

Pursuant to therequirements of the Securities Exchange Act of 1934, the Registrant has dulycaused this report to be signed on its behalf by the undersigned thereunto dulyauthorized.

|                          | ** ** | **ENBRIDGE ENERGY PARTNERS, L.P.**                                                                          |
|--------------------------|------------|-------------------------------------------------------------------------------------------------------------|
| ** **               |       | (Registrant)                                                                                                |
|                     | By:        | Enbridge Energy  Management, L.L.C.  as delegate of  Enbridge Energy Company, Inc.  as General Partner |
| Date: July 31, 2006 | By:        | /s/ STEPHEN J. J. LETWIN                                                                                    |
|                     |       | Stephen J.J. Letwin                                                                                         |
| * *                 | * *   | *Managing Director*                                                                                         |
| * *                 | * *   | *(Principal Executive Officer)*                                                                             |
| Date: July 31, 2006 | By:        | /s/ MARK A. MAKI                                                                                            |
| * *                 |       | Mark A. Maki                                                                                                |
| * *                 | * *   | *Vice President, Finance*                                                                                   |
| * *                 | * *   | *(Principal Financial Officer)*                                                                             |

 

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